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This paper reviewed the interpretation of repeat fall-off tests acquired in two vertical pattern injectors operating in a carbonate reservoir undergoing full field development. Water Alternating Gas first pattern (WAG-1) started in August 2002 with a period of continuous gas injection until 2006 when the first water cycle was initiated. In the second pattern (WAG-2) water injection was initiated in June 1998 until September 2007 when the first gas cycle started. A few pressure fall-off tests were acquired during the monophasic injection phase mostly to verify well injectivity. After Water Alternating Gas (WAG) cycles started, pressure fall-off tests were usually acquired at the end of each three-month injection cycle with 1:1 WAG ratio. Analytical fall-off test interpretation relied on the use of the two-zone radial composite model. The apparent permeability thickness product was corrected with the Perrine formulation of multiphase mobility. Triphasic oil permeability was calculated using the modified Stone I model. Multiple fall-off test interpretations indicated that the two pattern vertical injectors behaved differently even though both being fractured. The difference in behavior was linked to different perforated intervals and reservoir properties. Gas and water injection rates were showing differences between both pattern injectors as a consequence. No major operational issue was reported during the three-year operation of both WAG patterns. During the WAG cycles, gas banks were found to be of a small inner radius and almost undetectable at the end of the subsequent water cycle. Changes in the pressure derivative slope at the end of the subsequent water injection cycle indicated most likely the creation of an effective mixing zone of injected gas and water in the reservoir. Numerical finite-volume simulation was required to account for potential injected fluid segregation and, the multi-layered and heterogeneous nature of the reservoir. Repeat saturation logs acquired in observation wells provided critical information on the saturation distribution away from the injection wells. Enhanced vertical sweep conformance through phase mobility control in the presence of strong reservoir heterogeneity was the major expected benefit from an immiscible WAG displacement mechanism. All available observations were reviewed and integrated using a history-matched reservoir simulation sector model with boundary conditions obtained from a full-field model.

Multiphase flow measurements (MPFM) have gained the oil and gas industry focus since the early 90’s(1) due to its continuous improved performance and ease of remote operations (1). Different MPFM systems have been developed but none of them can be referred to as absolutely accurate (3). One of the commonly used systems combines Venturi meter with gamma ray fraction meter (4). The latter is simple, robust and extremely accurate for a given composition based on physical measurements. However, the sensitivity of the nuclear attenuation to heavy atoms can lead to drastic uncertainties on Water Liquid Ratio (WLR) measurements. Therefore, applications where heavy atoms composition changes with time represent an operational and economical shortcoming for surveillance engineers and field operators due to the need to frequently update the configuration data set of such MPFM systems every time the wellstream composition changes. This paper provides surveillance engineers and field operators with a methodology that has been developed and validated while commissioning new permanent MPFM units on three major onshore fields in the UAE. Several sensitivity studies were carried out to determine the impact of lumping well configuration profiles into groups and assess the MPFM measurements sensitivity to various physical and compositional flow parameters such as phase densities, viscosities, %H2S, %CO2 and water salinity. It also offers a cost effective solution in order to optimize the time and cost required for initial and/or frequent MPFM configuration work by introducing pre-determined configuration data sets that takes into account the wellstream compositional variation with time. The suggested methodology was applied on 247 wells producing from five different reservoirs. It has significantly reduced the man-hour required to complete the individual well profile configuration from 60 days to 8 days. Once the methodology is implemented, it requires no further vendor support and no frequent physical reconfiguration. For MPFM systems that do not rely on nuclear attenuation technology, the methodology still can be applied to identify measurements sensitivity envelope to any physical, chemical and/or mechanical parameters.