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Obtaining an adequate fluid characterisation early in the life of a reservoir is becoming a key requirement for successful hydrocarbon development. This work presents and discusses a number of new fluid sampling and fluid characterisation technologies that can be deployed either down hole or at surface in the early stages of the exploration and development cycle to achieve this objective. Techniques discussed include methods to monitor and quantify oil-based mud contamination, gas-liquid-ratio (GLR) and basic fluid composition in real time during open-hole formation testing operations. In addition, we demonstrate the applicability of new surface analysis techniques that allow for rapid, accurate, and reliable measurements of key fluid properties, such as saturation pressure, gas-oil ratio, extended carbon number composition, viscosity, and density, on-site within a few hours of retrieving reservoir fluid samples at surface. Finally, prediction tools used to extend these limited measurements to a traditional PVT fluid characterisation are presented along with example measurements from all the techniques described. In conclusion, it is shown that the implementation of these techniques in a complementary program can reduce the risk associated with making key development decisions that are based on an understanding of reservoir fluid properties.

The current world petroleum industry situation is that:➢Exploration is difficult and costs are increasing.➢The majority of hydrocarbons being exploited today are found in existing pressure depleted or complex and lower quality reservoirs➢Current oil prices are up-and-down Thus, world circumstances have forced today’s petroleum industry to rethink both its operating methods and technologies aiming at improving recovery and reducing cost. It is believed that adoption of new technologies is the most important factor in adding reserves, enhancing recovery, reducing cost and increasing revenue. Underbalanced drilling technology is now seen as the way to achieve these objectives.

The current world petroleum industry situation is that:Exploration is difficult and costs are increasing.The majority of hydrocarbons being exploited today are found in existing pressure depleted or complex and lower quality reservoirsCurrent oil prices are at their highest Thus, world circumstances have forced today's petroleum industry to rethink both its operating methods and technologies aiming at improving recovery and reducing cost. It is believed that adoption of new technologies is the most important factor in adding reserves, enhancing recovery, reducing cost and increasing revenue. Underbalanced drilling technology is now seen as the way to achieve these objectives. Introduction Underbalanced Drilling - UBD- main objectives are:Preventing formation damage and improving Reservoir Benefits.Improving Drilling Performance & Preventing Conventional Drilling Problems. This paper discusses in details the reservoir benefits part of underbalanced drilling technology. What is Underbalanced Drilling? Underbalanced Drilling is the intentional reduction of the drilling fluid density causing the hydrostatic pressure in a well bore to be lower than the pore pressure within a formation thereby permitting reservoir fluids to be produced while drilling. Underbalanced Drilling benefits the reservoir by simply adding reserves through: Discovery of new zonesReducing formation damage and increasing intra-zone contributionLowering abandonment increasing well drainage areaAccessing challenging reservoirs Providing real time reservoir evaluation / characterization. Although UBD has many advantages, it is not a magic potion for all fields, wells or drilling problems. Poor execution and planning would result in an over-enthusiastic misapplication of the technology, and possibly failure. Several real results and case studies will be presented and discussed in this paper.

Identification of the produced hydrocarbon liquid stream, as either oil or condensate, in two-phase hydrocarbon reservoirs, gains special significance in cases where the gas cap and its associated condensate owners are different from the oil rim owners. Thus, the definition of the produced hydrocarbon liquid stream is critical in determining the allocation of the produced liquid phase and accounting for the volumes of oil and condensate produced to satisfy marketing constraints. In this paper we will discuss classification procedures of the produced hydrocarbon liquid stream, laboratory sampling and analysis, and compositional modeling demonstrated for a saturated oil reservoir with a large gas cap and a critical fluid reservoir. Introduction The definition of the hydrocarbon liquid stream and the characteristics of oil or condensate received significant focus in the petroleum literature. Appropriate sampling and conventional analysis of oil and condensate was discussed as early as 1941 by Flaitz et. al.1 and later in 1954 by Reudelhuber2,3,4. Eilerts et. al.5 in 1957 reported observed characteristics of a number of condensate fluids highlighting the wide range in physical properties and deriving "rule of thumb" to classify condensates based on gas-oil-ratio (GOR) and API gravity. In 1986 Moses et. al.6 discussed the characteristics of oil, near critical fluid and condensate, his work received significant discussion that advanced the understanding of the defining characteristics of the hydrocarbon fluid systems. A more detailed classification was presented by McCain et. al.7,8,9,10,11,12. McCain's classification identified color, API gravity and gas-liquid ratio (GLR) as defining characteristics of the produced hydrocarbon stream. Legal definitions and classifications were also adopted by various governmental agencies and are applied as references. Specifically, the Alberta Mines and Minerals Act 13,14 and the 1988 OPEC classification15. The significance of establishing an agreed criteria and procedure to classify and allocate oil and condensate production is realized in mixed ownership, where the owners of the oil and condensate are different. For mixed production situations, that will inevitably evolve during the development cycle of two-phase hydrocarbon reservoirs, present a challenge in determining the accurate allocation ratio of oil and condensate. We will demonstrate that appropriate periodic sampling and analysis of mixed producing wells provide the technical basis of validating compositional modeling techniques capable of component tracking permitting differentiation of liquid streams originating from the gas-cap or oil column. The procedure was applied to a saturated oil reservoir and a critical fluid reservoir and the results and specific technical challenges will be discussed.