This paper expounds the value of integrated decision based planning in delivering field development plan (FDP) in a LEAN way. The basic philosophy of lean is waste minimization or elimination of non-value adding activities to improve efficiency, quality and lead-time. Integrated decision based planning is considered as the most pragmatic and efficient approach in integrated reservoir modelling process. Dynamic modeling is the most preferred tool assisting subsurface decisions making. Nevertheless, the data centric approach with support of scaled reservoir model has the advantage over the conventional full field physics-based models specially, in case of a complex reservoir. Embracing the basic lean principles with focused decision based reservoir modeling strategy can establish a new level of performance within the organization in delivering FDPs. The Saih Rawl oil field (SRS) in North Oman is a thin Lower Cretaceous carbonate reservoir with post diagenetic imprint. Post oil fill structural change has resulted in re-saturation and oil trapping due to local capillary imbibitions. The complexities resulting from the tilted water contact, hysteresis in oil mobility and Sor variation with depth, pose a huge challenge in dynamic simulation. In addition, drilling feasibility for horizontal infill wells was quite challenging due to subsurface collision issues and rig footprint interference with existing surface facilities. Integrated decision based planning, linked to the subsurface and surface decisions was adopted for framing the integrated reservoir modeling (IRM) strategy. The IRM strategy with Decision Based Models (DBM), including analytical and sector simulation models, were used to understand the sweep pattern, locate the remaining oil and rank the various water-flood patterns. Data analysis including normalized decline-curve-analysis (DCA) based conduit models and comprehensive field performance analysis using Spotfire (an integrated data visualization and analysis tool by TIBCO), was used to understand the key reservoir management risks and infill potential. Throughout the process, the basic philosophy of lean was adopted embracing several lean tools to improve productivity, quality and lead-time. Out of 12 subsurface feasible options studied, the proposed optimum option envisages an increase in the oil recovery factor by 9% by drilling an additional 92 infill wells in 22 patterns. The successful completion of frontend loading phase of SRS project has achieved reducing in the FDP study time to 19 months compared to an average of 36 months in the past and project implementation 4 years ahead of the original plan. Fast tracking of the project implementation was possible due to standardization of the equipment, maximum utilization of the existing infrastructure and constructive collaboration with the stakeholders. The key enablers for the successful delivering of the SRS FDP study were mainly the integrated decision based planning with data centric approach in reservoir modeling workflow and adoption of basic lean principles This approach emphasizes the importance of adopting lean tools in frontend delivery process. The decision based planning with reservoir models linked to the project decision can significantly improve the efficiency and quality of the FDP. The stakeholder alignment and strong collaboration with key stakeholders of the project can further reduce the lead-time of project execution. The decision based IRM planning used for this study sets a benchmark for future FDP studies. The Urban Plan study approach for this project has also become the standard for other LEAN FDPs.

This paper presents the results of a comprehensive study carried out to improve the understanding of deep bottom-up water injection, which enabled optimizing the recovery of a heavy oil field in South Oman. Understanding the variable water injection response and the scale of impact on oil recovery due to reservoir heterogeneity, operating reservoir pressure and liquid offtake management are the main challenges of deep bottoms-up water injection in heavy oil fields. The offtake and throughput management philosophy for heavy oil waterflood is not same as classical light oil. Due to unclear understanding of water injection response, sometimes the operators are tempted to implement alternative water injection trials leading to increase in the risk of losing reserves and unwarranted CAPEX sink. There are several examples of waterflood in heavy oil fields; however, very few examples of deep bottom water injection cases are available globally. The field G is one of the large heavy oil fields in South Oman; the oil viscosity varies between 250cp to 1500cp. The field came on-stream in 1989, but bottoms-up water-injection started in 2015, mainly to supplement the aquifer influx after 40% decline of reservoir pressure. After three years of water injection, the field liquid production was substantially lower than predicted, which implied risk on the incremental reserves. Alternative water injection concepts were tested by implementing multiple water injection trials apprehending the effectiveness of the bottoms-up water injection concept. A comprehensive integrated study including update of geocellular model, full field dynamic simulation, produced water re-injection (PWRI) model and conventional field performance analysis was undertaken for optimizing the field recovery. The Root Cause Analysis (RCA) revealed many reasons for suboptimal field performance including water injection management, productivity impairment due to near wellbore damage, well completion issues, and more importantly the variable water injection response in the field. The dynamic simulation study indicated negligible oil bank development due to frontal displacement and no water cut reversal as initial response to the water injection. Nevertheless, the significance of operating reservoir pressure, liquid offtake and throughput management impact on oil recovery cann't be precluded. The work concludes that the well reservoir management (WRM) strategy for heavy oil field is not same as the classical light oil waterflood. Nevertheless, the reservoir heterogeneity, oil column thickness and saturation history are also important influencing factors for variable water injection response in heavy oil field.

The Amin field located in South Oman is one of the PDO's major producing oil fields. The reservoir is good quality sandstone formation with average porosity of 28% and average permeability of 800 mD. Prior to 2014, the field was developed using natural depletion drive during which some parts of the field experienced significant pressure depletion. This depletion was due to combination of high production from the crestal area and the presence of a near field-wide intra baffle (L110), that restricts the aquifer response to the upper layers of the reservoir. The baffle about 2m to 4 m thick is a cemented sandstone with minor shale intercalation that has caused the vertical pressure variation across baffle L110. To arrest the field pressure depletion, water-injection was implemented since 2014, for further field development. Produced water is injected into the aquifer below the OWC of the field through 38 vertical injector wells. To achieve desired voidage replacement injection is expected with fracturing conditions using untreated produced water with injection rates > 1500 m3/day. Bottom hole pressures are at or above formation fracture pressure and decline in injectivity with time has been observed due to untreated water. Geomechanical data and modeling results were integrated with WRM activities, trials data and surveillance technologies to optimize the injection strategy for improved waterflood performance. Geomechanical data was acquired to estimate the formation fracture pressure to provide guidance on maximum allowable injection pressure in injectors with perforations closer to OWC to manage the risk of induced fracture growth. A Produced Water Re-Injection (PWRI) fracture modeling and analysis was performed to determine the potential fracture dimensions to provide input to development decisions of injection rate and perforation depth below OWC. Simulations were carried out with estimated range of formation fracture pressure, Petrophysical parameters, injection rate forecasts and expected water quality parameters e.g. TSS (Total Suspended Solids) The simulation results from the field data calibrated PWRI fracture model indicate that injection higher rates > 1500 m3/day, would result in vertical fracture growth from the injection depth. The rate of fracture growth is primarily influenced by water quality and depth of injection. Formation fracture pressure decreases with depletion therefore once the vertical fracture propagates and enters into the upper reservoir zone, fracture growth will be accelerated. Results indicated that if injection depth closer to OWC can result in short-circuiting as early as 2 years for certain field area. Higher injection rates to meet the desired voidage replacement ratio has significant impact on the field's waterflood performance. Results provided inputs to reservoir simulations and injection rate envelope for varying perforation depth below OWC. The study benefits the field to minimize risk of injector producer short-circuiting for improved waterflood management.

This paper discusses the urban planning process applied for field development of one of the biggest and most congested field in sultanate of Oman. The field has a carbonate reservoir contains a light oil with associated gas. The reservoir is currently under waterflood development. The oil production is co-mingled with other fields at production station and the produced water is pumped back into the reservoir for pressure maintenance and the remaining is disposed into another reservoir. The field contains an area layout of 22 km °18 km. The new development proposal of further infill drilling at a narrower spacing was challenging in term of well interference with existing infrastructure, spacing, rig movement and accessibility. The first pass of checking the wells locations feasibility shows that only 30 percent of the wells can be drilled due to massive amount of existing wells with surface infrastructure. It was not easy to develop and drill the majority of proposed wells with required surface infrastructure. A detailed urban planning study was carried out to address the inherent issues and challenges associated with re-development of the field. An integrated multi-discipline team was formulated consisting of, Concept Engineering, Geomatics, Production Geologist, Reservoir Engineering and Well Engineering. A close coordination was also maintained with other relevant disciplines to address the surface development issues and for making the quality concept decisions in early phase of the project. The process of urban planning applied in this study was documented as a best practice within the company and cross learnings were used as basis during the study and also captured in Urban Planning Guideline which was developed internally. Resolving the challenges for placement of wells on surface and rig accessibility for drilling challenged the normal ways of working and triggered the un-conventional thinking to establish the well drilling feasibility and integration with surface scope. Consequently, project team have come up with ways to drill the wells that would not be drilled by following the normal way of working. Integrated urban planning enabled the proposed number of wells to be drilled despite the insufficient space to accommodate standard pits and pads. In conventional approach, initial urban planning assessment concluded feasibility of drilling only 30 percent of proposed wells. However, the team managed to improve the feasibility of drilling those wells up to 90 percent. This has allowed the maturation of the planned target hydrocarbon volume and created huge value in re-development of this field. Tangible benefits also achieved in early decision-making, up to two months schedule acceleration could be realized in field development through integrated urban planning approach. Study has demonstrated that urban planning can save approximately 10 percent in off-plot CAPEX. On top of this, urban planning has helped in lowering HSE risks during the drilling and reducing production deferment during construction.

Global experience in cold Gas Oil Gravity Drainage (cGOGD) recovery with crestal gas injection of infield produced gas is very limited, but is a proven economic recovery method for fractured carbonate reservoirs in North Oman. Despite decades of research in nature of fluid flow in fracture-matrix media and application of sophisticated tools in building fracture model of a naturally fractured reservoir (NFR) reliable prediction of the GOGD production performance often proved elusive. Characterization of fracture networks and modeling of matrix-fracture transfer function, gravity induced fluid flow in heterogeneous matrix media especially in case of capillary discontinuity due to tight interbedded matrix and capillary pressure hysteresis are the key challenges for reservoir modeller. Re-infiltration of oil into lower matrix blocks, matrix permeability, fracture density and spacing, wettability and reservoir fluid properties have significant impact on the well and field performance. The risk posed due to undermining the key modeling parameters have huge implication on facility design, subsurface concept and value of the project. The challenges in upscaling the fracture properties in a range of grid scale, experimental design for history matching and uncertainty analysis, understanding the oil rim development in leached zone and numerical options are some of the key aspects which have been illustrated in this paper. The field being on primary production since 1985, showed poor recovery and high water cut. Multi-episodic tectonic events resulted in variable fracture intensity and fracture permeability anisotropy. This study investigated the effects of the parameters on cGOGD recovery process, operating strategy (e.g., gas injection rate and liquid offtake) and on the overall field performance. The development decisions are not simply relied upon the dynamic simulator results, but an integrated understanding from comprehensive analytical calculations for multiple recovery mechanism such as fluid expansion, fracture oil displacement, gravity drainage from background matrix and leached zone and analogue field GOGD performance were taken into consideration. The subsurface development decisions such as producer location with respect to faults and lineament, well pattern & spacing, producer depth, gas injector locations, gas injection scenarios, aquifer pump-out wells and maximum off-take rate were analyzed and optimum decision could be taken from multi-scenario modeling studies. The GOGD development could increase the field recovery up to ~9% at low UTC and positive NPV. A pragmatic and integrated modeling workflow with multi-scenario modeling approach was pursued to address the development risk which facilitated the field to be economically developed. The key modeling challenges have been highlighted for GOGD modeling process with gas recycling option of development which can be replicated in similar fields in PDO.