In this paper, we present the workflow and strategy used to define key success criteria and Reservoir Monitoring Plan (RMP), for a unique Hybrid CO2 EOR pilot in an Abu Dhabi carbonate Field. The EOR method known as SWAG (Simultaneous Water and Gas) injection responds to the need to counteract the permeability contrast observed in the field between the upper and lower layers of the reservoir to increase oil recovery from CO2 in the tighter lower part of the reservoir. A numerical simulation strategy was used to define the pilot's success criteria with detailed monitoring plan to de-risk the main uncertainties. Defining success criteria for EOR pilots must ensure criteria are measurable, quantifiable and realistic. In this work, we looked in addition at the timing of occurrence in order to accurately plan for data acquisitions, adequate sampling frequency and correct tool selection to build a robust Reservoir Monitoring Plan (RMP). A detailed sector model was built in the pilot area using a refined grid to capture the water and CO2 fluid movement and any changes in saturation expected in nearby observers. Cross sections were built and numerical saturation profiles were extracted for the pilot wells to determine expected arrival time of CO2 and waterfronts and define frequency of log acquisitions and fluid sampling. Success criteria were then defined with supported values and timings to define the required duration of the pilot and ensure that key uncertainties would be de-risked. Fit for purpose RMP was designed covering baseline acquisitions planned during the drilling of the pilot wells, followed by monitoring during the pilot and post pilot acquisitions. Success criteria for CO2 SWAG was defined to cover Operational aspects, Subsurface EOR Performance and HSE and Integrity. Operational aspects found to be most critical were CO2 and water injection uptime, ensuring the required Pore Volumes (PV) of CO2would be injected to fully assess the Sweep Efficiency and performance of the CO2 SWAG. Subsurface Performance included criteria such as minimum reservoir pressure to ensure miscibility, well productivity and injectivity, CO2 breakthrough and GOR and CO2production profile trends to be monitored through PLTs, fluid sampling and analysis, and tracer injection. HSE and Integrity included corrosion and cement logs in both pilot and neighboring wells. Numerical simulations showed that placing an observer at 75 m from the injection wells provided the most reliable data, while location at 50 m was also explored to accelerate data gathering for model calibration required to de-risk Full Field implementation. Changes in saturation in the observer wells showed that CO2 breakthrough would be observed after 1 year with a 50 m observed and 1.8 years for 75 m observer location. Profiles are shown from simulation after 1 year of starting the pilot, showing that the 50 m observer would capture CO2 arrival in the lower interval, while at 75m only the upper layers would have shown CO2 sweep. Kv/Kh is one of the key uncertainties to be de-risked with time-lapse saturation monitoring during the pilot.

Reservoir development using Maximum Reservoir Contact (MRC) wells has taken significant leaps and bounds in the oil and gas industry in the last fifteen years with horizontal well length of more than 2500 meters. MRCs, a breakthrough in drilling technology, has enabled us to drill long horizontal producing or injecting sections, especially in low permeability or tight oil bearing layers. In such reservoirs, with the increased reservoir contact surface area, the wells are able to produce and inject at higher rates with lesser drawdowns. This increased productivity index helps to delay the gas and water breakthrough, reduce the conning and improve the GOR/Water-cut response. Hence, improving the sweep efficiency and the ultimate recoveries. On the other hand, MRC wells could potentially help to address the subsurface and surface congestion challenges especially in brown fields by reducing the overall development well count by 2 to 3 times. The production gain from long horizontal section is limited by the pressure drop within the well bore from toe to heel. Therefore, there is a technical limit to the production gain that can be achieved by increasing the horizontal section length. Drilling beyond this limit will incur cost without any prominent production gains. Hence, there would be a techno-economic limit to the optimal MRC well length. This paper present the screening study conducted to determine the optimal well length for an MRC well from a techno-economic point of view. A mechanistic fine gridded sector simulation model is used for this study. The MRC wells are segmented and considers the well bore hydraulic calculations for all the pressure loss elements. Different MRC well length scenarios are considered to compare the sweep efficiency and ultimate recoveries. The cost to benefit screening analysis is conducted for various MRC lengths, in relation with their associated costs and dynamic performance. The techno-economic analysis indicates that the MRC well length of around 10K ft is the optimal. Beyond this length, there is a marginal increase in incremental NPV and the relative difference in reduction of UTC gets minimal. The paper highlights the importance of a value assurance study conducted for the MRC well lengths that can potentially be considered for optimal field development/re-development. Each reservoir with its specific rock and fluid characteristics would worth this type of screening study with the help of numerical simulation tools. The choice of MRC well length would eventually have a great impact on the field development economics.