PDO is a major operator in the Middle East with long production history for many of its oil fields. Due to the increased gas supply requirements, it is considering options for blowing down the gas caps of some selected oil fields to cater for the gas demand for achieving sustainable oil production. The key challenge for these gas blow down is to maximize gas production plateau while simultaneously minimise associated oil recovery losses. This Case Study illustrates the Gas Blowdown optimisation of a saturated clastic oil reservoir. During the Blowdown Study, optimum gas production rates from each of the Upper and Middle Gharif reservoirs are targeted to meet a given gas production plateau rate. A fit-for-purpose assessment for the impact of subsurface parameter uncertainties on the proposed development demonstrated robustness of the gas production plateau period. This analysis resulted in a Gas production Plateau period ranging from 4 years (Low case) to 7 years (High case) with an expectation case of 6 years. Multiple Subsurface & Surface development scenarios have been evaluated including lowering pressure ratings for the Separator inlet pressure. The oil & gas production profiles thus generated have been evaluated for robust economics and used for final concept selection & field implementation. Furthermore to minimise oil losses various optimisation efforts have been identified during pre and post blow down phases in terms of re-perforations, gas lift implementation and blow down oriented well and reservoir management practices. This case study proposes an optimised Gas Blowdown field development by maximizing gas plateau period while minimizing associated oil loss. The Study resulted in selecting the appropriate surface development concept, operating specifications and provided an optimised field management plan during the Blowdown phase. The methodology adopted in this case study should find wider applicability in the industry.
The case study carbonate field has been developed by waterflooding. Presently, only the produced water is re-injected into 50 wells with voidage replacement ratio being less than unity at field level. Declining pressure trends due to suboptimal voidage replacement balancing and continuous drilling activities require rigorous monitoring to avoid dropping below a critical reservoir pressure (13000 Std. Units ) level at which the hydrostatic head could initiate fractures in the reservoir. Injection under fracturing condition is not an option for field recovery furthermore preventing artificial fractures will be safeguarding 40% of expectation reserves in three specific injection patterns. A geo-mechanical study was conducted to understand the dependency of fracture pressure on reservoir pressure depletion, including temperature effects. A geo-mechanical model was generated using well logs such as density & sonic that was calibrated with lab tests for rock mechanical properties and leak-off tests together with pore pressure for stress model. This model was then used in the estimation of fracture pressure dependency on reservoir pressure using poro-elastic theory. A pragmatic diagnostic tool was then developed for establishing the field pressure operating envelope, where the injection pressures are plotted against reservoir pressures and compared to the field operating envelope at pattern level.. This tool helps identify which patterns are at potential fracturing risk. i.e. above fracture pressure model. Consequent to identification of risky patterns, mitigation measures are implemented by reducing water injection rates and/or reducing offtake rates to adjust sector pressure within the operating envelope. This remediation is practiced rigorously every quarter for all the patterns with the availability of updated reservoir pressure data. So far no indication of induced fractures from downhole temperature gauges or anomalous water-cut behavior is seen. With the effective injection pressure/rate management, field ultimate recovery is estimated to be 33%, exceeding the top quartile recovery factor (32%) and a sustained expectation oil production forecast for the coming 7+ years. To further enhancing the voidage replacement, two supply water wells were drilled for supplementing water injection In summary, better management of waterflood projects dictates controlling injection strictly below fracture pressure compared to maintaining injection closely above bubble point pressure. The proposed waterflood field management methodology adopted is generic and the diagnostic tool developed can be utilized routinely for preventing induced fractures in matrix waterflood projects.
PDO has a diverse portfolio of mature fields undergoing waterflood. These fields open-up an additional opportunity through infill drilling for enhancing the ultimate oil recovery. It has been established in the oil industry that increased well density does not only result in acceleration but will also lead to incremental recovery. This paper demonstrates the approach taken for identifying and maturing an infill development in a Shuaiba matrix carbonate reservoir within a thin oil column. The case study field has been developed predominantly with single long (~ 1.5 km) horizontal oil producers (lifted with ESPs) & water injectors in a Producer-Producer-Injector (PPI) pattern with a ~60 m spacing between Producer and Injector (P-I).The development team executed additional appraisal activities in parallel with implementing the field development plan. Seismic inversion was updated with the new well results which improved porosity prediction in un-drilled areas. Based on acoustic impedance guidance, appraisal wells have been drilled with encouraging indications in terms of producibility and opened new areas for further development. The history matched simulation model results showed that 120 m P-P-I spacing would recover 25% of in place volumes compared to 60 m P-P-I spacing with an ultimate recovery factor (URF) of 45%.The key success factors for the infill development are (1) well placement with geosteering, (2) balancing appraisal with development and (3) continually updating static and dynamic models. This is done to support development decisions such as well sequencing & placement, drilling activity and surface facilities expansion.The key learning from this case study is that developing fields initially with twice the proposed development spacing, nevertheless following the optimal water flood pattern, is the best way for appraising the whole field rapidly. This allows time to gather much needed information ahead of making tactical investment decisions on long lead-time surface facilities.
PDO operates many oil fields in Oman and maintains a periodical update of Field Development Plans (FDP). This paper presents a case study of one such green field where a FDP was performed that proposed numerous development wells targeting a thin oil rim overlain by a gas cap in two clastic transition-zone reservoirs. When drilling commenced, surprises were encountered such as steeper flanks, lower gross rates, higher water cut, faster pressure depletion & uncertain facies distribution. A comparison of earlier models against actual results lead to revisions mainly in vertical compartmentalization, reduced horizontal & vertical permeability. This severely impacted achieving business targets, and sub optimal use of drilling resources & surface facilities. A new FDP Study was initiated to understand the performance and provide a revised development strategy under pressure depletion conditions. The study also evaluated the merit of installing gas lift and the impact of gas cap pressure maintenance. Revised static & dynamic models were built with the current understanding from wells drilled since the previous FDP. The simulation model was history matched with field production & pressure data and then used to identify future well locations and optimum placement within the oil rim. Additionally, the numerical model was used to assess multiple development options such as oil gains arising from gas lift installation, assessment of an additional high-pressure gas compressor for deeper gas-lifting and an additional gas export pipeline. A fit-for-purpose uncertainty analysis of static and dynamic parameters was then undertaken to understand the range of uncertainty on field ultimate recovery. Screening of gas cap pressure maintenance resulted in a sizeable incremental oil volume over the depletion development, thus paving the way for future detailed concept selection of pressure maintenance field development. The study also resulted in identification of future infill well locations, immediate need for installation of gaslift and negated the need for an additional high pressure compressor & invalidated an additional gas export pipeline. Robust static & dynamic models were built through multiple iterations to provide a guiding tool for future development planning. The adopted methodology described in this paper to evaluate the various development aspects is generic and could be useful in typical field developments.
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