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The paper presents the evolution of reservoir management strategies that supported a recently drilled penta-lateral producer, which set a company record of total reservoir contact in a major greenfield in the Middle East. This paper will investigate the maximum reservoir contact (MRC) evolution in the field, the design phase of this game-changing producer, lessons learned and future implications.
The reservoir management objective for this producer was to capture oil reserves in tight layers (less than 10 md) in a gas cap driven carbonate reservoir while delaying gas breakthrough. This design was employed to push the MRC application to new limits of more than 16 kilometers to deliver more production at reduced well requirements while honoring best-in-class reservoir management practices.
In the design phase, a very high resolution reservoir simulation model was used to model the performance of this producer. Several sensitivity cases were conducted testing various well designs in terms of lateral spacing and completion depths. Subsequently, this producer was drilled with smallest lateral spacing (62 meter) closer to the oil-water contact (OWC).
The drilling of five laterals in 6 1/8" slimhole was a challenging task that posed hole cleaning threats across the horizontal sections and risked tight hole turning to stuck pipe. Through careful planning and team collaboration between various departments, the well was completed successfully with minor problems. In addition, the well was completed with two permanent downhole monitoring system (PDHMS) gauges and inflow control valves (ICVs) to manage water/gas movement and to ensure lateral clean-up.
Field Background: The greenfield is located in the South East part of the Arabian Penensuila and is primarily producing from one carbonate reservoir. The oil column in this reservoir is overlaid by a huge gas cap and is underlain by a weak aquifer. Gravity drainage mechanism with gas cap expansion is the main drive mechanism (Saleri et al. 2003).
Adedoyin, Orekoya (Bomo Keme) | Eteobong, Etokakpan (Bomo Keme) | Suleiman, Ahmed (Bomo Keme) | Basak, Prahlad (Shell Petroleum Development Company) | Ekwealor, Jude (Shell Petroleum Development Company) | Ejiuwa, Nworie (Shell Petroleum Development Company) | Remmy, Ugboaja (Shell Petroleum Development Company) | George, Kakayor (Shell Petroleum Development Company) | Onyeagoro, Kachi (Shell Petroleum Development Company)
The need for the estimation or evaluation Original Oil Water Contact (OOWC) prior to reservoir development is very pertinent to appropriate well placement within a reservoir. Oil and gas water contacts are determined via various sources including but not limited to Petrophysical logs, RCI data, Reservoir Simulation, Fault Seal Analysis (FSA), Quantitative Interpretation and Hydrocarbon Column Analogues. This paper focuses on an integrated approach of predicting OOWC using some of the methodologies highlighted above.
The study explores the feasibility of further oil development in the Yoko field to grow production and increase reservoir ultimate recovery. Three wells have been drilled so far in the field and none encountered OOWC. Three (3) key reservoirs account for about 69% of the total field hydrocarbon resource but with significant uncertainty in fluid contacts column (about 132ft) and wide static and recoverable volume range.
An effective and commercially viable field development plan is premised on the reduction of contact uncertainty. Inorder to narrow the contact uncertianty, a multidisciplinary approach has been used and they include (a) Petrophysical Logs (b) Analogue oil column studies from adjacent fields (c) Fault Seal Analysis (FSA) to determine maximum column in the reservoir (d) Quantitative Interpretation (QI) and (e) Dynamic simulation.
The analogue oil column from neighbouring field was used to benchmark the possible oil column for Yoko field. FSA which relies on the sealing capacity of the faults due to the amount of mechanical mixing from fault throws was also considered. The upper and lower limits of the fluid contacts were estimated from acoustic impedance amplitude plotted against depth. The reservoir dynamic models was also history-matched (7 years of production history) to calibrate and ascertain the limits of the possible contacts for the reservoirs.
The result of the evaluation is a significantly reduced volumetric uncertainty range. In one of the reservoir, there was a progressive reduction in fluid column uncertainty from 132 ft to 11 ft. In general 55 – 92% reduction of the initial uncertainty was achieved. This reduced range enabled a commercially viable Development Plan for the field.
Mamedov, Emil (Oil and Gas Research Institute of RAS) | Zakirov, Ernest (Oil and Gas Research Institute of RAS) | Arekhov, Vladislav (Gubkin Russian State Oil and Gas University) | Ahmetzyanov, Atlas (Institute of Control Sciences of RAS)
Contemporary traditional practice of 3D oil and gas reservoir modelling has severe drawback. Namely, the natural water flow is neglected. The main reason for this consist in complexity of combining two processes - the field development and natural water flow in the reservoir. This paper authors compared carefully four different approaches proposed by arabian and russian specialists for simulation of oil and gas reservoirs with tilted fluid contacts for using in software package of geological and hydrodynamic modeling. Advantages and disadvantages of the proposed approaches are revealed. Additionally, authors propose their own, the most realistic approach to taking into account the natural water flow for 3D simulation of oil and gas reservoirs with tilted fluid contacts and perfoming forecast calculations.
This paper presents drilling, completion, well performance, and reservoir characterization results of a recently-drilled Maximum Reservoir Contact (MRC) well in the Shaybah Field with a total of eight laterals and an aggregate reservoir contact of 12.3 kms (7.6 miles). The well was drilled as part of a pilot program to evaluate both the practical challenges and the reservoir performance impact of MRC wells.
Amaefuna, Magnus (The Shell Petroleum Development Company of Nigeria Ltd) | Ezenobi, Eric (The Shell Petroleum Development Company of Nigeria Ltd) | Okporiri, Cyril (The Shell Petroleum Development Company of Nigeria Ltd) | Ekwealor, Jude (The Shell Petroleum Development Company of Nigeria Ltd)
Clearly delineating contacts are usually aimed at before development, but what happens when later data indicates contacts different from what have been interpreted? How do we'work back in time' to re-estimate the original contacts? Our case study documents a reservoir which due to the poor well coverage, paucity of log data, side wall sample and pressure data, was initially interpreted as an oil bearing reservoir, however, a new well drilled post production of over 20 years indicated the presence of a huge gas cap, the size of which could not have been due to the formation of a secondary gas cap. This necessitated the determination of the original contacts in order to properly define the reservoir volumes which will impact on its future development. This paper presents the use of an integrated thinking approach which makes use of all the available geological, petrophysical and dynamic data in determining the original fluid contacts in a post production scenario. Reservoir simulation using simple tools as material balance combined with petrophysical and geological concepts were applied in this paper. The results obtained shows that the use of static data alone such as petrophysical logs in determining the original contacts for post production reservoirs can be greatly misleading as the results obtained may conflict with dynamic data available for the reservoir and therefore not fully representative of the reservoir and its history.