A complex heterogeneous carbonate reservoir, located in the offshore of Abu Dhabi, started oil production in 1985. The initial field development plan consisted of drilling crestal deviated producers and peripheral sea water injectors. As the reservoir is highly faulted and fractured with underlying high column of aquifer, water cut rapidly increased by channeling through faults system, reducing oil production. Consequently, the field development team decided to drill horizontal producers, and then later equip them with ESP. In the meantime, water injection rate was significantly curtailed due to uncertainty on injection benefit, which resulted in declining reservoir pressure, limiting production from some wells. In 2012, the team analyzed the historical production data to reassess water injection benefit. The study included areal analysis and correlations of reservoir pressure, voidage replacement ratio, logging data, production decline trends, bubble and saturation maps, and geologic data. The results indicated hydraulic communication between all reservoir areas, increased production decline rate with continuous reservoir pressure depletion due to low VRR and insufficient aquifer support, and poor pressure communication in some peripheral areas due to low reservoir quality resulting in lower transmissibility. Based on the analytical study results, reservoir simulation model was used to optimize water injection scheme, including optimum injector locations and optimum injection volume. Along the process, reservoir uncertainties were assessed through simulation sensitivities. The study results suggested maintaining the current peripheral water injection locations, increasing injection rate to minimize reservoir pressure depletion, working over the existing injectors/drilling new injectors to meet injection volume target, and carrying out further optimization after improved understanding of remaining geologic uncertainties. This reservoir management approach allows to continuously integrate reservoir geology and field dynamic data to reduce reservoir uncertainties and to optimize field development plan and operations.
The expected profiles of the water produced from the mature ADNOC fields in the coming years imply an important increase and the OPEX of the produced and injected water will increase considerably. This requires in-situ water separation and reinjection. The objective of in-situ fluid separation is to reduce the cost of handling produced water and to extend the well natural flow performance resulting in increased and accelerated production. The current practice of handling produced water is inexpensive in the short term, but it can affect the operating cost and the recovery in the long term as the expected water cut for the next 10-15 years is forecasted to incease significantly. A new water management tool called downhole separation technology was developed. It separates oil and & gas from associated water inside the wellbore to be reinjected back into the disposal wells. The Downhole Oil Water Separation (DHOWS) Technology is one of the key development strategies that can reduce considerable amounts of produced water, improve hydrocarbon recovery, and minimize field development cost by eliminating surface water treatment and handling costs. The main benefits of DHOWS include acceleration of oil offtake, reduction of production cost, lessening produced water volumes, and improved utilization of surface facilities. In effect, DHOWS technologies require specific design criteria to meet the objectives of the well. Therefore, multi--discipline input data are needed to install an effective DHOWS with a robust design that economically outperforms and boosts oil and/or gas productions. This paper describes the fundamental criteria and workflow for selecting the most suitable DHOWS design for new and sidetracked wells to deliver ADNOC production mandates in a cost-effective manner while meeting completion requirements and adhering to reservoir management guidelines.
The expected profiles of the water produced from the mature ADNOC fields in the coming years imply a 5-fold increase and the OPEX of the produced / injected water will increase considerably. This requires in-situ water separation and reinjection. The objective is to reduce the cost of handling produced water and to extend the well natural flow performance resulting in increased and accelerated production. The current practice of handling produced water is inexpensive in the short term, but it can affect the operating cost and the recovery in the long term as the expected water cut for the next 10-15 years is high. A new water management tool called downhole separation technology was developed. It separates Oil & Gas from produced water inside the wellbore and injects the produced water into the disposal wells. The Downhole Oil Water Separation Technology is one of the key development strategies that will reduce the handling Produced water, improve the recovery, and minimize field development cost by eliminating surface water treatment and disposal well. The main benefits for DHOWS are to accelerate Oil Offtake, reduce Production Cost, Lower Water Production and Improve facility Utilization. DHOWS require specific criteria to meet the objectives of the well. Multi-disciplined inputs are needed to properly install effective DHOWS, but robust design often brings strong performance. This paper describes the fundamental criteria and workflow for selecting the most suitable DHOWS design for new and sidetracked wells to deliver ADNOC production mandates cost effectively while meeting completion requirements and adhering to reservoir management guidelines.
This paper will focus on a new system for separation of water in downhole horizontal wells. The advantages with the system are related to the fact that the water produced from the well is not lifted to the surface, but re-injected into suitable parts of the reservoir, either for pressure support or for diposal. The method of water separation and re-injection has been evaluated for oil producing fields. The paper presents details of the technical solutions and analysis done related to the financial analysis/payback. The mechanical design is basically a main pipe section of a few meters of length, with a special geometry utilizing gravity-based separation. A technical and economic analysis of a downhole processing plant (DPP) using a horizontally installed water/oil separator has been performed. The Improved Oil Recovery (IOR)part has been analysed with a relevant flow simulation tool. Based on the given reservoir depth/pressure, flow rate, viscosity/density and water cut, the simulations show that a significant improved production rate/income can be achieved by extracting the produced water downhole and performing re-injection into the producing reservoir to maintain reservoir pressure. In addition, the expected lifetime of the well is increased by several years. The conclusion is that the earlier the separator is installed, the greater the total well income. In addition, details regarding not only multi-lateral wells through level 5 junctions but also production string with separator and valve system has been evaluated and is concluded to be feasible for the well in question The removal of water downhole has several advantages, for example the removal of the water column up to the surface will reduce the reservoir back pressure and will improve recovery /production rates. In addition, not lifting the water will reduce energy consumption/CO2 footprint, and removal of water will reduce surface processing and possible re-injection and chemical treatment cost. In general, water separation downhole is advantageous, due to the higher pressure.
This paper provides the learnings from a successful application of a smart completion in a complex heterogeneous carbonate reservoir. It details the study, planning, coordination, and implementation process of two pilot wells by a multidisciplinary team, and pilot production performance results, illustrating the success. First, to select an optimum completion design for the field, multi-segment well option and local grid refinement option were applied to the reservoir simulation model including calibration of faults/fractures. Second, based on the modified model, sensitivity analysis was conducted; 1) by selecting different types of completion including Open-hole, blank pipes (BP), compartmentalized slotted liners (SL), inflow control device (ICD) and hydraulic flow control valve (FCV); 2) by optimizing the number of compartments (packer and blank pipe placements for all cases), and ICD / FCV numbers and nozzle sizes. Using the data from the modeled cases, economic analysis was conducted, which indicated that the ICD in conjunction with sliding sleeves (SSD) was the best option. Two candidate wells were selected to cover the variation of reservoir characteristics: one well representing the heterogeneous part of the reservoir with high-density of faults, fractures and kurst, and another one representing the relatively homogenous part of the reservoir suffering from heel to toe effect. A multidisciplinary implementation team was set up to align all stakeholders on subsurface requirements, following up the completion design, coordinating material procurement and logistics for mobilizations, daily drilling operations follow-up, real-time logging data interpretations and completion design adjustment. Evaluation of the two pilots’ results based on predefined KPIs during the study, exceeded overall expectations.
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