Al-hinai, Suleiman Mohammed (Petroleum Development Oman) | Van Wunnik, John N.M. (PDO) | Thum, Matthias (Petroleum Development Oman) | Brissenden, Simon John (Petroleum Development Oman) | Mukmin, Mukmin (Petroleum Development Oman) | Al Nofli, Sami Mubarak (Petroleum Development Oman) | Rabaani, Abdulsalam (Petroleum Development Oman) | Strauss, Jonathan Patrick (PDO) | Al-Breiki, Majdi
A number of thermal developments are currently in execution in Oman. Two of these are located in South Oman and contain an exceptionally thick column (200m+) of heavy oil (200 to 400,000 cp) in Cambrian reservoirs at a depth of 1050 m below surface, underlain by a moderately strong aquifer. One of the fields has been in production for 20 years, the main production mechanisms are pressure depletion and natural ingress of aquifer water, while the other field has only produced a small amount by cyclic steam stimulation (CSS) trials due to the high viscosity of its heavy oil. For the next phase of development a vertical well pattern re-development is planned which will increase the ultimate recovery significantly, through a combination of cold production, CSS and steam flooding.
The thickness of these reservoirs is unusually large for steamflooding and this poses both opportunities and challenges. There are no direct analogues and the industry practices of managing a steamflood in this specific setting is yet to be verified. Phase I deliberately addresses only the upper parts of the reservoirs while significant volumes are still to be matured in a future Phase II development. Following some higher level screening work of recovery mechanisms, the realistic development options for Phase II are innovative application of further steam flooding. Subsurface uncertainties are actively managed by different means; among them are the steam injection trials and steam pilot. The full field developments planned to start-up with Phase I in 2012 followed by Phase II in 2017.
The paper will provide an overview of the proposed Phase II thermal development and specifically the innovative way development challenges are addressed. The integrated modeling work that yielded a better design of well completion strategies will be discussed. Additional topics addressed include minimising additional gas requirements through application of co-generation of electricity and steam (COGEN), water management and overall integrated project management.
This paper describes key aspects related to conceptual well completion design and surveillance planning for an evolving polymer field trial in the South of Oman. An existing field was developed with mostly horizontal production wells drilled at the top of the oil column to deliver high oil production rates. The production of this medium-heavy oil is supported by a strong bottom drive. However, many wells have observed premature water breakthrough resulting in high water cuts and large volume of unswept oil. Polymer flooding using a horizontal well approach is proposed to improve sweep efficiency. If successful, this alternative approach has the potential to significantly improve oil recovery in the subject field.
Because of the significant investment required and novelty of the process (i.e. heavy oil, strong bottom water drive combined with the use of horizontal wells), a field trial is planned to address some of the development risks. Key subsurface risks and uncertainties include: possible polymer losses to the underlying aquifer, loss of effective matrix polymer injectivity, lack of polymer injection conformance along the horizontals and poor sweep efficiency. A number of activities were performed to help design the field trial and reduce some key risks and uncertainties i.e. laboratory coreflood, subsurface study, injectivity test and field visit to analogue field.
The study concluded horizontal polymer injectors placed between the existing producers and slightly deeper than the centre of the oil column is optimum to recover the unswept oil. Polymer injector with Smart completion is proposed to mitigate the lack of conformance along the horizontals. A detailed surveillance plan is critical to identify the required tools and technologies to facilitate data gathering and well intervention activities during the field trial. Proposed surveillance technologies are DTS, Multi Pressure Sensors (MPS) and saturation logging. Observation wells with glass reinforced epoxy (GRE) pipe are planned to get a higher accuracy and deeper investigation of the formation saturation. These activities will be supported by calibrated subsurface simulation models as new data is available to address the trial performance, as well as, better predict full-field performance.
Strauss, Jonathan Patrick (Petroleum Development Oman) | Alexander, David Mobey (Petroleum Development Oman) | Al Azri, Nasser Said (Petroleum Development Oman) | Al-Habsi, Mohammed (Petroleum Development Oman) | Al-Musallami, Talal (Petroleum Development Oman) | Koning, Maartje (Petroleum Development Oman) | Eriavbe, Francis Eseoghene (Shell Petroleum Dev Nigeria SPDC) | Mukmin, Mukmin (Petroleum Development Oman) | Al-Jarwani, Riyadh Mohammed (Petroleum Development Oman) | Landman, Anke Jannie (Shell Intl. E&P Co.)
This paper covers EOR development concept screening from a sub-surface perspective. The field in question is a medium sized heavy oil field with complex geology that is located in South Oman. The two front running concepts considered are steam and polymer flood, both of which present their own challenges. Common to both concepts are the difficulty in obtaining adequate conformance in a field that is characterised by high and highly variable permeabilities in a channelised environment and that includes lateral extensive shales that break the system up into vertically distinct sand units. Additional challenges are presented by a permeable regional scale aquifer, an erosive top surface that reduces the equivalent oil column (EOC) in the core of the field leaving thicker columns laterally close to the edge aquifer and the friable nature of the sand that makes sand control necessary. Challenges specific to steam are the relatively high initial pressure, inferred connection to a regional-scale strong aquifer, and relatively high CAPEX associated with the development. Polymer on the other hand represents a relatively untested option for oil with viscosities of greater than 400cP as are present in this field.
Modelling work used to identify risks and the subsequent development potential of these two options is presented. Potential development and maturation solutions for the various options are discussed and concepts are compared.
The structure is a four-way dip closed anticline caused by outward salt withdrawal and dissolution from salt walls outside the field limits (Figure 1). No extensional forces are required to develop this structure. A significant feature of the structure is its ‘bow-tie' shape, which is caused by the embayment in the south-east. This embayment is a result of the salt dissolution and is flanked by faults. The oil bearing reservoir is characterised by thin 10-20m Middle to Lower Gharif Permian age fluvial sandstones, of which the two upper Middle Gharif units (HSGHM4a and HSGHM4c) are the main pay that the developments target and will continue to focus upon (Figure 2). The lowest unit, HSGHLG2, is only oil bearing across the crest of the field and contains a small oil column with bottom water. It only accounts for a very small proportion of the total STOIIP and if it were to be brought on production is subject to extreme water coning behaviour and as such does not represent an attractive target for development. The three oil bearing units are separated by laterally extensive floodplain shales (HSGHLG1 and HSGHM4b) and unconformably overlain by the Nahr Umr Lower Cretaceous shales (Figure 2). The Gharif formation is underlain by the extensive glacial lacustrine ‘Rahab Shale'. Additional non-extensive shales are also present within the units, particularly in the uppermost HSGHM4c unit. The unconformity has resulted in some of the upper units of the reservoir being absent; no Upper Middle or Upper Gharif sands are present in the crest. In the three cores obtained in the field, the sandstones are observed to be very friable. Core permeabilities are typically high with 60% of the population above 1D and an upper limit of 10D that is more a reflection of measurement capability and core integrity than intrinsic permeability. Production performance supports the presence of multi-darcy (>5D) sands and three wireline mini-DSTs give single sand unit horizontal permeability averages of 4 to 8D.
Brooks, David (Shell Intl. E&P Co.) | De Zwart, Albert Hendrik (Shell Intl. E&P Co.) | Bychkov, Andrey (Shell) | Azri, Nasser (Shell International EP) | Hern, Carolinne (Shell) | Al Ajmi, Widad (Petroleum Development Oman) | Mukmin, Mukmin (Petroleum Development Oman)