A Comprehensive Study Developing and Maximizing the Recovery of Gas Condensate from a Giant Onshore Abu Dhabi Gas Field Utilizing Advanced Condensate Tracking, Gas Injection and Drilling Strategies in Next-generation Commercial Numerical Simulator

Abstract A comprehensive study of a giant onshore Abu Dhabi gas field using a next-generation commercial numerical simulator has been conducted. The objective was to identify the distribution and track the movement of the gas condensate in the reservoir, and to develop strategies to minimize the condensate drop-out and improve condensate recovery from the field. The field contains a large gas cap and an oil rim. We have identified the distribution of the gas condensate throughout the reservoir and were able to track its movement using the advanced fluid tracking option in the simulator. Once the gas condensate drop-out regions in the reservoir are identified, sensitivity runs with localized changes are carried out to improve the recovery from the reservoir. The strategies to mitigate drop-out include adding infill wells, drilling multi-lateral wells, reinjecting CO2 and dry gas into the reservoir, and hydraulic fracturing near the well bore. We were able to track the distribution of the condensate throughout the reservoir and identified key condensate drop-out regions. Adding infill wells improved the recovery of the condensate. Implementing multi-lateral wells also showed improved condensate recovery in the field. Hydraulic fracturing near the wellbore reduced condensate banking near the wellbore. Injecting dry gas improved the condensate recovery by a re-vaporization process where the liquid condensate is absorbed by dry gas. This paper discusses a comprehensive study on tracking the condensate distribution in a giant onshore field using a commercial simulator. The authors have performed a thorough investigation to identify an optimal condensate recovery strategy for the field, by comparing various recovery strategies using the full field reservoir simulation model.

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A Case History of Nitrogen Injection Monitoring in Rich Recycled Gas Condensate Reservoir, Onshore Gas Field, Abu Dhabi, UAE

10.2118/177790-ms ◽

2015 ◽

Cited By ~ 1

Author(s):

Hamza M. Hamza ◽

Mahmood Al Suwaidi ◽

Omar Al Jeelani ◽

Arafat Al Yafei ◽

Mahmoud Basioni ◽

...

Keyword(s):

Case History ◽

Gas Condensate ◽

Abu Dhabi ◽

Gas Field ◽

Nitrogen Injection ◽

Condensate Reservoir ◽

History Of

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Successful Development of Residual Gas Condensate Reservoir using First ESP in Deep High Pressure and Temperature in Rich Gas Condensate Wells

10.2118/207502-ms ◽

2021 ◽

Author(s):

Abdullah Salim Shuely ◽

Hilal Sheibani ◽

Hawraa Al Lawati ◽

Patrick Ezechie ◽

Roeland van Gilst ◽

...

Keyword(s):

Technology Implementation ◽

Success Factors ◽

Gas Condensate ◽

High Rate ◽

Geological Time ◽

Gas Field ◽

Produce Water ◽

Full Field ◽

Well Completion ◽

Residual Gas

Abstract A rich condensate gas field is located in the North of Oman, which penetrated the Amin sandstone reservoir at 4015 TVDmss. A study was conducted in the field and showed there is ¾ of GIIP trapped with paleo imbibition - over geological time - gas by the water encroachment in an approximately 80 m thick Paleo-Residual Gas zone (PRG), with very low mobility of hydrocarbons and high residual gas saturations. In order to mitigate the shortcomings of such unfavorable subsurface conditions, the study proposed Gas-Aquifer-Rate Management (i.e. co-production of gas and water) utilizing existing flank wells, as a potential field improvement option. The key business drivers for this project are to re-mobilize gas from PRG flank wells and to safeguard existing NFA by Aquifer pump off and production from high rate crestal wells. The optimum gas well deliquification method has been identified based on the highest UR considering connected GIIP and well completion size. The outcome of the study indicated that the ESP technology combined with well retubing was recommended as the optimum solution. Two wells have been selected as ESP candidates to test the new technology to produce water at deep depth (4000m) and high temperature (155°C). A special slim ESP was designed for this purpose. A successful pilot was completed in one well and gave conclusive results. The test showed that the well produced 3K m3/d of gas and 83 m3/d of liquid with 95% BSW. The second pilot is currently in the commissioning phase. The successful outcomes of the pilot succeeding in connecting the gas and restoring wells back with economic production rates will lead to expedite a full field implementation plan. This project will add a significant economic value of positive NPV at low UTC. This paper will highlight the full story of the PRG and ESP technology implementation and describe in details the entire process starting from the artificial lift selection, well candidate selection screening criteria, critical success factors, operating parameters, life-time cycle and the test results of gas and condensate and water production. Also, the learning and challenges in operating the ESP will be shared.

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Full Field Reservoir Simulation Study of an Oil Rim in a Field Offshore Abu Dhabi (UAE)

10.2118/87254-ms ◽

2000 ◽

Author(s):

Bruno Decroux ◽

Medhat El Emam ◽

Omar Nassar ◽

Talal Kadada ◽

Hagop Harakhanian

Keyword(s):

Simulation Study ◽

Reservoir Simulation ◽

Abu Dhabi ◽

Full Field ◽

Oil Rim

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Creating the Integrated Model for Conceptual Engineering of Reservoir Management and Field Facilities Construction – Experience of Tazovskoe Oil and Gas-Condensate Field.

10.2118/206540-ms ◽

2021 ◽

Author(s):

Artem Igorevich Varavva ◽

Renat Timergaleevich Apasov ◽

Dmitry Alexeyevich Samolovov ◽

Artem Viktorovich Elesin ◽

Gaidar Timergaleevich Apasov ◽

...

Keyword(s):

Growth Rates ◽

Oil And Gas ◽

High Growth ◽

Integrated Model ◽

Gas Condensate ◽

Gas Oil ◽

Full Field ◽

Conceptual Engineering ◽

Construction Experience ◽

Oil Rim

Abstract The paper describes the experience of building a full-field integrated model (PK1 reservoir) of the Tazovskoye field, including a model of the reservoir, wells, and a gathering network, taking into account the external transportation system. In order to integrate the features of the field, such as the simultaneous development of a thin oil rim and a gas cap, high growth rates of the gas-oil ratio, oil wells - both ESP-operated and flowing, algorithms and tools have been developed, which are discussed in the paper. The results of the integrated model runs are given, main features of the solutions are highlighted.

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Study Compares Fluid-Tracking-Modeling Approaches for Mature Onshore Field

Journal of Petroleum Technology ◽

10.2118/0921-0041-jpt ◽

2021 ◽

Vol 73 (09) ◽

pp. 41-42

Author(s):

Chris Carpenter

Keyword(s):

Gas Injection ◽

Oil Production ◽

Detailed Comparison ◽

Abu Dhabi ◽

Co2 Injection ◽

Full Field ◽

Field Level ◽

Carbon Dioxide Co2 ◽

Oil Rim ◽

Reservoir Simulator

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202747, “Fluid-Tracking Modeling for Condensate/Oil Production and Gas Use Allocation: An Abu Dhabi Onshore Example,” by Yun Wang and Gary Jerauld, SPE, BP, and Yatindra Bhushan, SPE, ADNOC, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. A reservoir in a giant field onshore Abu Dhabi has been producing for 6 decades. The reservoir was already saturated at the time of production commencement, with a large oil rim and a gas cap. This paper presents a comprehensive comparison of two modeling-based approaches of fluid tracking for condensate allocation and gas usage: a tracer modeling option in a commercial reservoir simulator and a full-component fluid-tracking approach. Introduction Examples of benchmarking fluid-tracking options against an independent fluid-tracking approach are rare in the literature. The goal of this paper, therefore, is to document a comprehensive and detailed comparison between the fluid-tracking option (TRACK) in NEXUS (a commercial reservoir simulator used by companies of the coauthors of this paper) and a full-component fluid-tracking (FCFT) approach. This work is motivated by the commercial arrangement of a concession covering an onshore field in Abu Dhabi. Because of different equity entitlements among the shareholders for the oil rim and gas cap per the concession commercial terms, a need exists to allocate the condensate vs. oil-rim oil production and the injected lean-gas usage. FCFT The idea of FCFT is relatively straightforward. Before discussing the approach, it is important to note that the focus of this paper is to compare the modeling of different tracking approaches. It is assumed that a fit-for-purpose fully compositional reservoir simulation model already exists. For fluid-tracking modeling with a full-field model (FFM), this means that the compositional reservoir model has already been history matched properly at both field and individual well levels and that no additional reconciliation is required before the hydrocarbon liquid and vapor streams are split into tracked substreams. In this paper, FCFT is completed on the field level for the comparison with the TRACK option in NEXUS. One could easily extend the field level tracking to either regional well-group levels or individual well levels. In the case of the onshore reservoir, lean-gas injection has been active during much of the producing history. In future development schemes under consideration, lean-gas injection, carbon dioxide (CO2) injection, and gas lift are all possible scenarios, raising the question of how to treat injected gas components within the FCFT framework. Different approaches exist to handle the injected gas components. One may treat the injected gas components as either the gas-cap components, the oil-rim components, or entirely new components. Lean gas injected in the onshore field example is actually a dry gas, according to the 11-component equation-of-state (EOS) prediction. Thus, the lean gas can be reasonably modeled with only one new component as long as that component replicates the volumetric behavior of the injected lean gas.

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