The use of pressure transient data in the field of Formation Testing in efforts to describe productivity and permeability of reservoirs is considered mature technology, particularly when applied to data collected through production testing. The extension of this technique to data obtained using Wireline Formation Testers, where either a single probe or a straddle packer is used to propagate a pressure pulse into a reservoir, has been gaining momentum in the industry over the past decade, however the integration of these outputs with other measurements of rock and fluid data is not always straight forward. This paper presents different methods of using pressure transient data from Wireline Formation Testers such as quantitative permeability determination, identification of permeability discrepancies in homogenous clastic formations, upscaling of permeability in a complex stacked reservoir and comparison of Wireline Formation Tester and conventional well test derived permeabilities. Additionally, this paper highlights the challenges one faces while planning, acquiring and interpreting pressure transient data from Wireline Formation Testers, as well as the importance of real-time monitoring and control of data.

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Heavy and ultra heavy oils are commonly found in many parts of the world. From MacGregor (1996), and UNITAR (1998), they were reported that conventional oil reserve is only 30%, but heavy oil and ultra heavy oil is 15% and 55%, respectively1. Proper reservoir characterization for these reservoirs is not always an easy task, especially when they are associated with (1) variation of different permeability formations (2) reservoir fluid viscosity including, extremely high viscosity fluids, (3) unconsolidated sand environments, and (4) Low Resistivity and Low Contrast Reservoirs. This paper presents different challenges of obtaining reservoir fluid information from six different heavy oil fields from the South of Oman where reservoir fluid viscosity ranges from < 100cp to more than 5000cp (at downhole conditions). The formation permeability varies from good permeability (Darcy range) to tight formation (<1 mD). Reservoir fluid identification and quality fluid samples are not easy and sometimes seems to be impossible with associated challenges. The used of openhole logs alone cannot be used to conclusively identify reservoir fluid, and therefore, Wireline Formation Testers (FT) or Full Scale Testing is required to reduce the fluid typing uncertainty and enhance reservoir characterization. This paper discusses challenges of formation sampling for both openhole and casedhole conditions for both heavy and ultra heavy oils. Three openhole and three casedhole field examples will be discussed in this paper from pre-job planning to operation results. For openhole cases, the use of 3D Radial Probe application will be introduced with different types of displacement downhole pump to help successful sampling operation. For casedhole cases, the dual packer FT were used to obtain reservoir fluids within the perforated interval. Due to complexity of these jobs, proper job planning was required to ensure the job objective can be achieved. This paper discusses pre-job planning in the casedhole considering the following (1) well control issue, (2) perforation types and lengths, (3) operation steps, (4) pre-job simulations for the formation tester tool selection, (5) results and recommendations for future jobs. This paper also introduces the use of Pressure Transient to help identify reservoir fluids. Pressure Transient Analysis (PTA) simulation Work will be presented in the casedhole section. Reservoir sampling can be done successfully even with reservoir and operation challenges in these wells using the right FT tools, pump types, and conveyance methods. From our experience, it can be concluded that pre-job planning and real-time monitoring were two keys to ensuring successful acquisition of formation representative heavy oil samples. Results of this paper help asset teams to minimize cost and obtain the most accurate reservoir information using our workflow.

Early information about reservoir fluid complexity, dynamic behavior, and reservoir connectivity is crucial for development planning and production optimization of new plays. Such impact is manifested in three main areas: (1) reservoir presence and connectivity to understand the extent of the play (2) reservoir fluid variation to understand the charge history and devise production strategy (3) completion optimization in exploration wells to maximize early production.Petroleum Development of Oman pursued an ambitious exploration campaign firstly consisting of 8 wells targeting a shallow, thin, complex lithology formation to better understand a new play, especially from reservoir extension and connectivity viewpoints. In addition to advanced formation evaluation logging consisting of elemental spectroscopy and nuclear magnetic resonance, an advanced Downhole Fluid Analyzer (DFA) was deployed with Wireline Formation Testers (FT) aimed to obtain formation pressure and fluid samples. The fluid scanning using in-situ fluid analysis was also performed to obtain reservoir fluid information in real time and at reservoir condition. In addition, Interval Pressure Transient Tests (IPTT) was conducted to evaluate permeability of each well.This paper provides the workflow of using the DFA and laboratory data for full field development. This will include discussion of DFA data such as asphaltene, fluid composition, Gas-Oil-Ratio (GOR), density, viscosity, and fluorescence yield to help draw a full picture towards reservoir connectivity.Having detailed fluid properties data available in real time allows to optimize the completion decisions (pump selection as one example) in order to maximize early production while allowing longer term reservoir management planning. This paper also discusses the use of in-situ fluid viscosity and pressure transient data to estimate zone permeability during the FT operation, which will later be compared to actual well test data. Results show a good comparison and provide comfort to use FT pressure transient data to evaluate zone permeability at early stage of the operation.The DFA data from the first 4 wells suggested the presence of subtle but distinct fluid differences in terms of composition, oil color, and fluorescence yields. This DFA data was then supported by full PVT laboratory results. The differences in fluids will be examined in more details. This paper will present an effective workflow to integrate pressure, DFA, and PVT data to understand reservoir connectivity issue in this newly discovered formation. In addition, the DFA color gradient model was then used to help supporting other available information.

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