The primary focus of a Well, Reservoir and Facility Management (WRFM) team is to guarantee shareholders’ return on investment by improving production and optimizing recovery. Several best practices abound in the industry to achieve this goal. Multi Rate Testing (MRT) is a statutory requirement on gas wells; one of the most important functions of MRT is to obtain the wells’ deliverability for optimal reservoir management. Obeahon et al (2015) had presented an alternative approach to Multi-Rate Testing using existing gas central processing facility. This approach is applicable provided all the metering equipment are installed. This paper presents an alternative MRT approach for gas plants which do not have all the metering equipment installed. This was applied in the OMAUO Field and can be applied on other fields with similar situation. OMAUO NAG (ONAG) operations had been plagued with the following problems: the absence of wet gas meters to measure the well potentials, uncertainty with CGR/WGR of the wells for model calibration/ well's optimization, challenge of conducting conventional MRT via third party due to cumbersome logistics/cost (ca. US$ 2 mln/well) and no test facility. Thus, potentials and deliverability can only be assessed via third party MRT operations and absence of wet gas meters had limited the ability to use the Gas Plant to carry out MRT. The proposed approach was executed by utilizing clamp-on meters (to measure wet gas) at the manifold and the Gas Plant as a giant test separator for the individual well testing. Pilot tests were successfully carried out on three wells that were tested individually (OMAU015T, 016T and 017T). The technical integrity of the acquired data was in line with that obtained from MRT via a test separator and the results of the analyzed data were found to be representative. The low CGR and WGR values obtained from the analysis also aligned with that obtained from the previous MRT (via third party mobile test separator). The pilot tests saved US$8mln for four wells tested with minimal HSSE exposure, gained additional volumes of gas (ca. 50 MMscf/d) due to the optimization exercise, reduced deferment by reducing execution time and aligns with the competitive drive within the oil and gas industry. The outcome of carrying out this pilot test via the use of clamp-on meters can be leveraged upon by other gas plants without requisite meters and test facilities.

Reliable gas well tests provide valuable data for production optimization and maximizing ultimate recovery of gas reserves. Poor data quality, heightened process safety risks and elevated OPEX are inherent limitations in the methods undertaken by operators to measure Condensate Gas Ratio (CGR) during Multi-Rate Tests (MRT) and routine production. This paper describes the steps undertaken by the team in BERA to overcome this challenge by utilizing the density-measuring capability of the Coriolis meter. A density-based algorithm was setup using a designed decantation procedure and encoded in the control system for real-time measurements and made available in the office domain. This technique provides improved data quality, ease of well surveillance and a long-term cost avoiding option while simultaneously increasing the flexibility and ease of executing MRTs. It eliminates the need for manual sampling with its associated process safety concerns.

Production system optimization is one of the key ways to derive value from existing assets and ensure optimal field development, by integrating all aspects of the production system from the subsurface to the surface networks. Over the years, various tools have been developed in the industry to aid complete system performance analysis and optimization. In most cases, the scope of optimization is limited to the as built fixed assets which often has limited scope for economic modification in the late life of the asset. Additionally, commingling compatible reservoir fluids using intelligent wells has been identified as a viable means of developing marginal stacked reservoirs, which are otherwise uneconomical if conventional development options are considered. Cosby field which is a prolific field in its late life, had been closed in for over 10 years due to asset integrity and subsequent flowline vandalization. The wells are completed mostly as Two String Dual or Multiple producers to target the stacked reservoirs. Field re-entry campaign provided an opportunity to optimize the approach to field development and bring in the wells which had been closed-in. However, the prevailing completion philosophy required each string to have dedicated flowlines ranging from 3000- 9000 ft. This is to convey the fluids from the well to the flow station; hence each interval had to meet an economic criterion to ensure competitiveness. This paper posits a "beyond blind spot" concept identified for the late life re-entry and optimization of the Cosby field oil wells; by identifying suitable candidates for surface fluid commingling using well and reservoir performance reviews and Integrated production system model as tools. This concept, which aligns with the competitive drive within the E&P industry, delivers a facility cost savings of ca. $2.24 million, and allows an economic potential addition of ca 1.5Mbopd and resource volume of ca. 5.2 MMstb to be safeguarded.