In south-eastern part of the Sultanate of Oman, PDO is producing from one of Tight Sour Field (with H2S 1-2%) with current reservoir pressures ranging from 40,000 to 60,000kpa for more than 20 yrs. Due to tight nature of reservoir, the wells are hydraulically fracced to produce, but with time the production rates decline and wells start to produce in unstable mode. This unstable production mode leads to huge scaling and corrosion issues which results in tubing failures requiring huge and expensive workover to restore well production. Due to low production rates and expensive workover makes these intervention very less attractive in terms of Net Present Value (NPV) compared to other opportunities. This paper describes the challenges in restoring production from wells with tubing leaks using conventional workover techniques and the advantages of using new approach of using Hydraulic Work Over Unit (HWOU/Snubbing unit) to workover these wells. Using HWOU for workover restoration time from the failure to restoring production has been reduced from ~2-3yrs to almost less than a year along with significant reduction in overall cost (more than 40% per well). This approach has been successfully applied to 2 wells till dates and upcoming workover will be done in similar manner.

In Southern Oman, PDO is producing from several critically sour fields (1-10% H2S). Initial flow assurance studies from these fields based on available data at the time did not predict asphaltene plugging issues in depletion mode for most of the fields. However, over the period, wells from one particular field (Field SA3) started experiencing asphaltene deposition in the wellbore, which initially affected only surveillance activities but later led to significant production deferment and posed operational challenges. This paper discusses the asphaltene management strategy developed by the team to tackle asphaltene problem in a systematic manner by improving the current asphaltene detection and cleanout techniques, which led to to reduction in unscheduled deferment by ~50% and the intervention costs by ~20-25%. This work also describes the potential asphaltene risks during gas injection based on an asphaltene study performed on downhole samples.

An Integrated Production System Model (IPSM) is an essential tool to study the interactions between multiple reservoirs, wells and surface networks for any integrated optimal development. This paper describes a fully implicit IPSM for two interacting production system networks (critically sour facilities with >5% H2S) with multiple oil reservoirs and undergoing Miscible Gas Injection (MGI) for Enhanced Oil Recovery (EOR) using produced sour gas from oil and condensate fields in South Oman. A range of up to 17 reservoir models, with different complexities, were incorporated in this IPSM. Larger reservoirs were modeled using 3D, fully compositional, numerical discretized models, whilst smaller ones were based on decline curves. A new production system is connected to an existing system, within a closed loop, honoring all nodal constraints, e.g. multi-stage separators, gas compression, gas sweetening, and heat exchangers. Priorities were assigned such that sweet gas export commitment is achieved first, followed by miscible gas injection to oil reservoirs and gas recycling to a condensate reservoir for production optimization. An Equation of State (EOS) model is used to model the complex interactions of different fluids, at reservoir and facilities levels. This IPSM has been set-up to provide accurate and consistent short to long term forecasting, optimizing on oil/gas production and recycled gas injection. All surface network constraints are honored and cut-back logics based on different prioritizations are behaving reasonably. Current capabilities include determining the optimal strategy for development of these portfolio of reservoirs based on the different value drivers, tracking of composition for components like H2S that limits gas sweetening units and affects miscibility in reservoirs and longevity of the facilities. The IPSM is also intended for optimizing near-field potential in mature fields and developing new fields while operating under the facilities constraints. It can be used to analyse various business opportunities in the reservoirs and surface facilities (such as low-pressure operations) to the appropriate degrees of complexity. This work involved integration and collaboration across multiple disciplines, identifying complex interactions between facilities constraints and reservoir performance (associated with produced gas reinjection), through an implicitly coupled EOS IPSM. Fluid blending in the surface network, and recycling and apportioning of produced gas from the seventeen reservoirs for re-injection after meeting export requirements and honoring all system constraints and priorities makes this problem quite unique and challenging

South Oman's critically sour oil fields are producing for last more than 2 decades from over-pressured carbonate-stringers that are encapsulated in salt. There is no aquifer support in most of the discovered stringers and existing facilities are designed with close to zero water handling. However, unlike other adjacent fields, another sour field Field-A had a strong aquifer; hence required a CAPEX intensive surface facility for water handling or a strategy for field development with dry oil only. Field-A is prolific undersaturated oil reservoir with light oil (45-API), excellent productivity (well-test KH:~20000md-m) and very strong aquifer (R-ratio:9-10). The field was initially developed with 5 oil producers. Due to near zero water tolerance at the facilities, the regular surface sample collection and analysis were conducted to monitor any water production. For proactive Well Reservoir Management (WRM), the time-lapse PNX logging (Pulse-Neutron-Extreme) was deployed in 2017 to regularly monitor the behind-casing contact movement and hydrocarbon saturation changes. Field development scenarios of high-offtake with water or controlled-offtake of dry oil and arresting the OWC movement (as seen in PNX) were evaluated. During the initial development, higher per well offtake led to faster OWC movement and generation of large water cones. First PNX logging survey acquired in 2017 revealed that the current OWC has moved up approx. 60-70 m with strong oil desaturation in all the wells. As an immediate response to it, the offtake per well was halved with introduction of regular annual monitoring of oil water contact movement by the PNX logging. The time lapse PNX surveys acquired in 2017-20 revealed the contact movement pace has been arrested after implementing the lower per well offtake since 2017. The previous further development plan of the field was to build a large CAPEX intensive water handling facility to handle water during oil production. However, the well surveillance information confirmed the benefits of gravity stable displacement process and the better displacement efficiency by reduced well offtakes with favorable mobility ratio present in the field with excellent reservoir properties. This led to a significantly cost-effective field development plan which was based on reducing per well offtake, increasing the infill count and producing dry oil only. This work reinforces the value of WRM stream and operational excellence into the field development plans for capital efficiency. Implementation of the well reservoir surveillance and management-based development plan yielded RF ~50% with dry oil production and eliminated the need of large water handling facility in sour environment, paving the way for a competitive further development plan of the field which was 75% cost effective than previous development plan. This work can be beneficial to similar developments to emphasize embedding WRM streams for cost reduction staircase of field development.

Well delivery in Pre-Cambrian salt with high-pressure floaters in the South of Oman provides several challenges, including Well Control Events, losses, supercharging, salt creeping, casing collapse and a negative drilling windows if section TD is picked incorrectly. The well design does not allow for an additional casing string with redundancy to case of troublesome zones. To overcome this, PDO initiated a barefoot completion as an extra hole section instead of well abandonment. As a wells recovery plan in 2017, PDO initiated different potential options to complete Ara salt wells and one of visible alternative options was to complete wells as open hole "Barefoot" completion. A design solution developed across technical functions on the suitability of barefoot completion in the carbonate reservoirs. The method to drill and complete with 3.615" hole as "Barefoot" was then expedited through detailed design as per the well delivery process. Key factors, which were considered included inflow performance and hole stability, the review of BHA design, drilling hydraulics, fluids selection and barrier considerations for barefoot completion. The operational challenges were reviewed and optimized with each implementation to drive further value. To date three wells recovered successfully with the new barefoot completion method. The wells completed with solids free drilling mud placed across the reservoir section and a suspension plug installed in the upper completion to facilitate rig release. During well testing operations; the suspension plug is removed, the openhole section is clean-up with coil tubing to remove filter cake with Enzyme treatment and finally the carbonate reservoir stimulated with gelled acid. During production tests all wells showed excellent production results and reservoir flowing coverage confirmed by spectrum noise logs (SNL), high precision temperature (HPT) and production logs (PLT). Based on three wells results; it is concluded that openhole completion can offer a valuable completion option for well recovery & may be used for optimization for current designs. The cost of the barefoot completion delivery has reduced by 20%. The production output from the wells is higher than expected; Productivity Index of those wells is relatively much better than the nearby wells. The Newly proposed design provide continuity to develope Ara Salt wells and recovery plan to overcome challenges and avoiding well abandonments. This completion option was reviewed and accepted as base case completion for some deep fields in South of Oman, where oil is encapsulated in high-pressure carbonate floaters and there no risk of water or gas breakthrough. One more additional well was planned to be completed as openhole "Barefoot" completion and cost saving of ~15% over the total well cost was achieved. This recovery option will benefit all the upcoming future wells in the area.