Masalmeh, Shehadeh K. (Shell Technology Oman) | Wei, Lingli (Shell International Exploration & Production B.V.) | Hillgartner, Heiko (Petroleum Development Oman) | Al-Mjeni, Rifaat (Shell) | Blom, Carl P.A. (Shell Intl E&P)
Enhanced oil recovery (EOR) has become increasingly important to maintain and extend the production plateaus of existing oil reservoirs. Simulation models for EOR studies require the right level of spatial resolution to capture reservoir heterogeneity. Data acquired from the dedicated observation wells are essential in defining the required resolution to capture reservoir heterogeneity. For giant reservoirs with long production history, their full field models usually have grid block sizes that are of similar scale as the distance between injectors and observation wells, with the consequence of losing the value of the time lapse saturation logs from dedicated observation wells. Therefore, using high resolution sector models, especially from the part of the reservoir where static and dynamic data sets are rich, is a must.
The objective of this paper is to present an improved and integrated reservoir characterization, modelling and water and gas injection history matching procedure of a giant Cretaceous carbonate reservoir in the Middle East. The applied workflow integrates geological, petrophysical, and dynamic data in order to understand the production history and the remaining oil saturation distribution in the reservoir. Large amounts of field data, including time lapse saturation logs from observation wells, have been collected over the last decades to provide insight into the sweep efficiency and flow paths of the injected water.
Iterative simulations were performed to investigate different scenarios and various sensitivities with each iteration involving an update of the static model to honor both the dynamic and core/log data. While applying this iterative process it was also acknowledged that conventional core data (e.g. 1 plug per foot) may not capture the high permeability streaks in these heterogeneous reservoirs that control much of the reservoir flow behaviour, hence much denser plugging and core examination is required. In addition, permeability upscaling procedures need to take into account the fact that core plugs may not represent the effective permeability of the larger connected vuggy pore systems.
The improved understanding of reservoir heterogeneity, the more robust reservoir characterization, and the improved history matching demonstrates that a better representation of reservoir dynamics is achieved. This provides a solid platform for designing and planning future EOR schemes.
Carbonate reservoirs contain more than 50% of world's remaining conventional hydrocarbon reserves and on average have relatively low recovery factors. With the insight that the era of "easy oil?? (conventional oil and natural gas that are relatively easy to extract) is phasing out, enhanced oil recovery (EOR) becomes increasingly important to maintain and extend the production plateaus from existing oil reservoirs. EOR technologies, however, require a refined understanding of reservoir heterogeneities and dynamic field performance. Simulation models for EOR studies need to have the right level of resolution and details. Often, we find that for a giant reservoir with a long waterflood history, working with full field models with coarse simulation grids is not adequate to understand the reservoir performance and calibrate the static model. Therefore, using high resolution sector models, especially from the part of the reservoir where static and dynamic data sets are rich, is a must.
Hillgartner, Heiko (Petroleum Development of Oman) | Paino, Wan Faisal (Petroleum Development of Oman) | Hadhrami, Fahad (Petroleum Development of Oman) | Mukhopadhyay, Arunesh (Petroleum Development of Oman) | Al-Sinani, Ibrahim Said (Petroleum Development of Oman) | Naamani, Ali (Petroleum Development of Oman) | Al-Habsi, Ranya (Petroleum Development of Oman) | Subhi, Wahab (Petroleum Development of Oman) | Vander Heyden, Frederic
The carbonate reservoir in question is located in the northwest of the Sultanate of Oman and was developed first in depletion mode since 1970. From the year 2000 until today a horizontal water flood scheme has been implemented. The reservoir is made up of 2 carbonate layers of 27 and 13 meters thickness intercalated with several meter thick shale layers. They form the deepest reservoir layers of the Cretaceous Natih Formation. The reservoir layers are composed of laterally continuous, microporous, low permeability (5-10mD) limestone that is interpreted to be heterogeneously but overall sparsely fractured. The implemented water flood in this field is considered to be well behaved with a stable oil production and low water cuts of around 20 to 25%.
An integrated field study was carried out for a planned horizontal infill development. The main objective was to obtain a representative set of static and dynamic models that match historic production. One of the principal challenges was the unknown impact of fracturing and faulting on the intensified water flood development in the reservoir layers and on the potential vertical communication within and with overlying reservoir layers.
Seismic, geological, petrophysical, and reservoir data were integrated with drilling and production information to produce a detailed matrix and fracture description of the reservoir. Several iterative workflows that included numerous feedback loops with reservoir simulation results were applied to achieve an appropriate history match and confidence into the predictive capabilities of the reservoir model and the simulation forecasts.
The main achievements of the applied workflow are a major reduction of the uncertainties related to the impact of faults and fractures on reservoir behavior. Key was the close integration of simulation results of the dual porosity permeability model and field data. The modeling workflow of the matrix and fracture models and their implementation in the reservoir simulator were optimized in such a way that uncertainty evaluation was entirely handled in the simulator and simulation times were reduced significantly.
This study has clearly shown that even in reservoirs that appear to be relatively simple and well behaving with respect to the chosen development option may require a much deeper level of understanding and may reveal significant complexities. In the presented case the reservoir formerly believed to be "simple matrix dominated reservoir?? shows a significant heterogeneity in fracturing across the area of interest. Only detailed understanding after comprehensive data integration, construction of a dedicated continuous fracture model and a dual porosity permeability simulation model allowed achieving reliable predictions on reservoir behavior. The study has led to improved well planning and well and reservoir management practices in response to sudden increase in water production.
The applied workflows may serve as an example for comparable carbonate reservoirs with apparent sparse fracturing that, however, may impact water flood development.
This paper presents a method for improving oil recovery from heterogeneous mixed to oil-wet carbonate reservoirs. In reservoirs where a high-permeability zone is above a low permeability zone, under water flooding the injected water tends to flow through the upper zone along the high permeability layers with no or very slow cross flow of water into the lower zone, resulting in very poor sweep of the lower zone. It has been demonstrated in earlier publications that this water override phenomenon is caused by capillary forces which act as a vertical barrier and counteracts gravity force in cases where permeability varies between layers for mixed to oil-wet reservoirs.
There is significant scope for improving oil recovery from such type of heterogeneous mixed to oil-wet carbonate reservoirs. Gas injection is known to improve displacement efficiency by reducing residual oil saturation. However, for reservoirs of high permeability contrast especially when the high permeable layers are in the upper part of the reservoir, conventional gas injection (immiscible or miscible) becomes less effective because of gravity override and/or viscous fingering caused by unfavourable mobility ratio compounded by geological heterogeneity. The main challenge to gas injection in such reservoirs is to confine the gas into the low permeability zones and improve sweep efficiency. Therefore, for this type of carbonate reservoirs, mobility control is required to enable gas/CO2 EOR due to the geological heterogeneity and gravity override.
This paper presents a new EOR scheme where mobility control of the injected gas is achieved by injecting viscosified water into the upper zone while injecting miscible gas into the lower zone using vertical and/or horizontal wells. A key prerequisite is to have a static model that captures the geological heterogeneity (e.g., vertical permeability contrast, all prevailing rock types) and a dynamic model that incorporates the SCAL derived capillary pressure (both drainage and imbibition) and relative permeability curves. Integrated geological, petrophysical and reservoir engineering effort was devoted to this EOR program that led to history matched sector models which honours the waterflood remaining oil saturation distribution shown in cased hole time-lapse saturation logs. The model forecasts show that significant sweep of the lower zone is achieved compared to both water or gas injection and that the process is stable and robust to reservoir lateral and vertical heterogeneity.
This EOR process has the potential of recovering the oil that is by-passed by waterflood or conventional gas injection schemes. It is particularly suited for layered oil reservoirs where there is an impediment for water to flow from the upper high permeable zone to the lower reservoir due to e.g. (vertical) permeability reduction at the interface or a capillary pressure barrier. It is also applicable for improving oil recovery from the low permeable layers inter-bedded within the more permeable reservoir unit. Additional benefit of this process is to potentially enable economic EOR and CO2 storage in such kind of heterogeneous reservoirs.
Rawnsley, Keith (Shell E&P Technology Co.) | Al-Hadhrami, Fahad (Petroleum Development Oman) | Kok, Apollo Leonard (Petroleum Development Oman) | Moosa, Riyadh (Petroleum Development Oman) | Swaby, Peter (Shell E&P Technology Co.) | Al Dhahab, Salah (Shell E&P Technology Co.) | Bettembourg, Solenn (Shell E&P Technology Co.) | Engen, Geir (Petroleum Development Oman) | Richard, Pascal Daniel (Petroleum Development Oman) | de Keijzer, Martin (Shell E&P Technology Co.) | Penney, Rick (Petroleum Development Oman) | Boerrigter, Paulus Maria (Shell E&P Technology Co.) | Pribnow, Daniel F.C. (Shell Intl. E&P Co.) | Koning, Maartje (Shell E&P Technology Co.) | Hillgartner, Heiko (Shell E&P Technology Co.)
An intensely fractured reservoir in central Oman is being developed by injecting steam into the crest of the field, heating the oil in the matrix and producing it via a Gas-Oil Gravity Drainage (GOGD) process. Both the static and the dynamic data support a strongly fractured (and leached) reservoir. Building 3D full field fracture models that capture the possible scenarios proved to be a challenge, largely because to date (i) most wells in the crest are vertical, (ii) a limited number of horizontal wells have been drilled on the flanks, (iii) seismic quality is relatively poor, and (iv) dynamic constraints on the permeability structure are limited, especially on the flanks. A new 3D fracture software tool (SVS) has been used to maximize the value of fracture-related reservoir data through improved integration, visualization, analysis and correlation. Rapid interactive analysis of the data set allows the user to efficiently characterize and understand the nature of the fracture system and its relationships to other reservoir parameters.
The data analysis indicates that two end member fracture system scenarios could be present in the reservoir i) a mechanical stratigraphy related and ii) fault/corridor related fracture system. This is particularly true of the flank wells, which despite being mostly located away from the main seismic scale faults on the crest, have evidence for fault related fracture clusters at intervals down the well bore. For these end member, and intermediate scenarios, "Low", "Medium" and "High" Case models were created using fracture trend maps/grids that combine the data and a range of geological constraints. More remote information was included from outcrop fault patterns in northern Oman. A combination of detailed process based discrete fracture generation and rapid fracture attribute generation was used to populate over 15 full field simulation grids capturing the range of remaining uncertainty of the fracture system across the field.
The field studied is an elongated dome structure that lies at relatively shallow depth. The field contains heavy oil within a relatively tight matrix in the Shuaiba, and the Kharaib reservoir units. To recover the heavy oil, steam is injected at the crest, passes into the extensive crestal fracture system, and starts to heat the matrix blocks.