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Summary Hydrocarbon-gas injection is one of the most widely applied processes in the oil industry and is a promising enhanced-oil-recovery (EOR) method for use in Middle East carbonate oil fields. Gas injection improves the microscopic-displacement efficiency and generally acts as pressure maintenance; however, unfavorable mobility ratio can negatively affect the ultimate recovery because of viscous fingering and gravity override. This paper describes two gas-injection pilots that have been implemented in offshore Middle East carbonate reservoirs: a secondary and a tertiary gas injection through line drive to assess injectivity, productivity, macroscopic-sweep efficiency, flow assurance, and operational efficiency in a field that has a long water-injection history. A strong monitoring plan, including an observer well, was applied through time-lapse saturation logging, pressure measurements, production testing, and a tracer campaign to evaluate the pilot efficiency and address key uncertainties upfront before full-field application. This paper describes the pilot performance in the context of full-field development, local- and macroscopic-displacement efficiency, flow-assurance issues, and operational learnings. The gas-injection performance is strongly affected by reservoir heterogeneity, gravity segregation, and the existing pressure gradient, and the history match performed indicates near-miscible or miscible behavior depending upon local pressure regimes, which thus govern the ultimate recovery. The history match also shows that for the same pilot, performance can be further improved through water-alternating-gas (WAG) injection, resulting in a viable development scheme for full-field implementation.

Hydrocarbon gas injection projects are undertaken in order to maintain reservoir pressure, produce oil through swelling and reduce residual oil saturation by decreasing the interfacial tension (IFT). Along with local displacement efficiency, macroscopic sweep efficiency plays a dominant role in the success of gas injection projects, as recovery from the field depends strongly on reservoir geology and petrophysical properties. In this paper, a case study of one of the hydrocarbon gas injection pilots is discussed as the performance of the other two pilots has already been described in Kumar et al. 2015a. A five-spot pattern hydrocarbon gas injection pilot in tertiary mode has been carried out in a giant carbonate reservoir offshore Middle East, which has long peripheral water injection history. A comprehensive monitoring plan, including an observer well, was applied through time-lapse saturation logging, single well chemical tracer test (SWCTT), pressure measurements, production testing, and tracer campaign to assess the pilot performance and minimize uncertainties before large-scale application. This paper presents the overview of the pilot, monitoring plan and the findings which include microscopic and macroscopic sweep efficiency. The pilot areal sweep performance was affected by the existing pressure gradient of peripheral water injection while the vertical sweep efficiency was strongly affected by the reservoir heterogeneity. At the cessation of the pilot, a value of 6 ± 3% was measured from SWCTT in the producer well, which shows the robustness of the gas local displacement efficiency. The history match performed indicates that for the same pilot, the performance can be improved using horizontal line drive in place of five-spot pattern and it can further be enhanced through water-alternating-gas (WAG) injection. The learning from the three gas injection pilots is used in re-designing the future large-scale development plan and is described in details in Kumar et al., 2016a and 2016b.

Hydrocarbon gas injection is the most widely applied process after waterflooding, and is a promising enhanced oil recovery (EOR) injectant for use in Middle East carbonate oil fields. Gas injection improves microscopic displacement efficiency and generally acts as pressure maintenance; however, unfavorable mobility ratio can negatively impact the ultimate recovery due to viscous fingering and gravity override. This paper describes two gas injection pilots that have been implemented in offshore Middle-East carbonate reservoirs, a secondary and a tertiary gas injection through line drive to assess injectivity, productivity, macroscopic sweep efficiency, flow assurance and operational efficiency in a field that has long water-injection history. A strong monitoring plan, including an observer well, was applied through time-lapse saturation logging, pressure measurements, production testing, tracer campaign, etc. to evaluate the pilot efficiency and address key uncertainties upfront prior to full-field application.This paper describes the pilot performance in the context of full-field development, local and macroscopic displacement efficiency, flow assurance issues, and operational learnings. The gas injection performance is strongly impacted by reservoir heterogeneity, gravity segregation and the existing pressure gradient, and the history match performed indicates near-miscible or miscible behavior depending upon local pressure regimes, which thus govern the ultimate recovery. The history match also shows that for the same pilot, performance can be further improved through water-alternating-gas (WAG) injection, resulting in a viable development scheme for full-field implementation.

The design of solvent-based and solvent assisted heavy oil recovery processes requires accurate predictions of phase behavior as straightforward as saturation pressures and as potentially complex as vapour-liquid-liquid equilibria and asphaltene precipitation. In this case study, saturation pressures of dead and live bitumen were measured in a Jefri PVT cell at different concentrations of a multi-component solvent at temperatures from 20 to 180°C. Saturation pressures and the onset of asphaltene precipitation were also measured for the bitumen diluted with n-pentane. The onset of precipitation was determined by titrating the bitumen with pentane and periodically circulating the mixture past a high pressure microscope.The data were modeled with the Advanced Peng-Robinson equation of state (APR EoS). The maltene fraction of the bitumen was characterized into pseudo-components based on extrapolated distillation data. The asphaltenes were characterized based on a Gamma distribution of the molecular weights of selfassociated asphaltenes. The APR EoS was tuned to match the saturation pressures by adjusting the binary interaction parameter between the solvent and the pseudo-components via a correlation based on critical temperatures. Rather than adjusting the interaction parameters for each pair of components, only the exponent in the correlation was adjusted. The role of mixing rules in correctly predicting the onset and amount of asphaltene precipitation is discussed.

In a giant offshore UAE carbonate oil field, challenges related to advanced maturity, presence of a huge gas-cap and reservoir heterogeneities have impacted production performance. More than 30% of oil producers are closed due to gas front advance and this percentage is increasing with time. The viability of future developments is highly impacted by lower completion design and ways to limit gas breakthrough. Autonomous inflow-control devices (AICD's) are seen as a viable lower completion method to mitigate gas production while allowing oil production, but their effect on pressure drawdown must be carefully accounted for, in a context of particularly high export pressure. A first AICD completion was tested in 2020, after a careful selection amongst high-GOR wells and a diagnosis of underlying gas production mechanisms. The selected pilot is an open-hole horizontal drain closed due to high GOR. Its production profile was investigated through a baseline production log. Several AICD designs were simulated using a nodal analysis model to account for the export pressure. Reservoir simulation was used to evaluate the long-term performance of short-listed scenarios. The integrated process involved all disciplines, from geology, reservoir engineering, petrophysics, to petroleum and completion engineering. In the finally selected design, only the high-permeability heel part of the horizontal drain was covered by AICDs, whereas the rest was completed with pre-perforated liner intervals, separated with swell packers. It was considered that a balance between gas isolation and pressure draw-down reduction had to be found to ensure production viability for such pilot evaluation. Subsequent to the re-completion, the well could be produced at low GOR, and a second production log confirmed the effectiveness of AICDs in isolating free gas production, while enhancing healthy oil production from the deeper part of the drain. Continuous production monitoring, and other flow profile surveys, will complete the evaluation of AICD effectiveness and its adaptability to evolving pressure and fluid distribution within the reservoir. Several lessons will be learnt from this first AICD pilot, particularly related to the criticality of fully integrated subsurface understanding, evaluation, and completion design studies. The use of AICD technology appears promising for retrofit solutions in high-GOR inactive strings, prolonging well life and increasing reserves. Regarding newly drilled wells, dedicated efforts are underway to associate this technology with enhanced reservoir evaluation methods, allowing to directly design the lower completion based on diagnosed reservoir heterogeneities. Reduced export pressure and artificial lift will feature in future field development phases, and offer the flexibility to extend the use of AICD's. The current technology evaluation phases are however crucial in the definition of such technology deployments and the confirmation of their long-term viability.

He received his Ph.D. from the University of Colorado. He has been teaching engineering for 30 years. His interests are colloidal/interfacial phenomena, reactor design and engineering education.

Severe Asphaltene deposition is encountered in some wells drilled in newly developed reservoirs of one of Abu Dhabi's giant offshore assets (Field AD), and for the first time, full well plugging with Asphaltene is experienced in the field. While successful curative clean up treatments are regularly made, the relatively high intervention frequency (once every month per well) has impeded the full-scale development of these reservoirs. This study shows how understanding the mechanism of Asphaltene stability/instability in field conditions can unlock the production of under-developed reservoirs (with hundred millions barrels of OIP) by anticipating and considering preventive measures during the design of new wells to limit Asphaltene deposition. In order to prevent the occurrence of Asphaltene deposition from reservoir formation to surface level, a Flow Assurance study was launched by the operating company with close support from the international partner. The objective was to determine the Asphaltene Deposition Phase Envelope (ADE) of the reservoir fluid by measuring onset pressures with Visual (High Pressure ‘HP’ Microscope) and Near Infrared Solid Detection System (SDS) as a function of 2 main variables: Different temperatures to investigate Asphaltene risks over the oil production pathway (at reservoir formation, and from wellbore to surface facilities) & Different Gas compositions to investigate the effect of rich Gas-Cap gas and injected lean gas on the Asphaltene stability. Also, the segregation of the nature of Asphaltenes within the reservoir has been investigated by using the experimental approach named ‘ASCI (Asphaltene Solubility Class Index) experiment’ introduced by the international partner (SPE-164184) to rank Asphaltenes’ solubility with atmospheric dead oil samples taken in different locations. In addition to that, 2 more experiments were performed: Organic – Inorganic test on solid sample to determine the composition and the nature of the solid deposit (whether it is Asphaltene or other type of depositions) & SARA analysis on atmospheric samples. This paper presents the improved work-flow based on the collaboration of the local operator and the international partner, introduces the use of ASCI (Asphaltene Solubility Class Index) experiment and discusses the results of the study and its way-forward.