A new generation of sampling technology is introduced that allows a wireline formation tester (WFT) to sample reservoir fluids in open hole with levels of filtrate contamination that are, in many cases, below measurable limits. Also, the time required on station to clean up before sampling is significantly reduced in comparison to conventional sampling methods.

Formation-fluid sampling has always been adversely affected by mud-filtrate contamination, which introduces errors into the laboratory measurements of fluid properties and requires analytical methods to back-calculate the measured properties to approximate the uncontaminated reservoir fluid. The ability to secure a totally clean sample of formation fluid at reservoir conditions is a significant advance that provides accurate fluid information for characterization of the reservoir, flow assurance, facility design, production strategies, and defining reserves.

The application of this new focused sampling technology is presented in four case studies from wells drilled on the Norwegian continental shelf. A wide range of formation fluids and permeabilities are examined, in both oil-based and water-based drilling fluids. Results from focused sampling are compared directly with conventional sampling in the same reservoir zones. This study also gives insight into the cleanup dynamics of invaded filtrate and explores the different factors that affect performance of the focused sampling technique.

An important consequence of achieving negligible contamination is the ability to accurately measure fluid properties in-situ. Reduced cleanup time allows for efficient reservoir fluid profiling, whereby multiple zones can be scanned sequentially in real time to quantify the fluid properties at a much higher resolution than traditional sampling methods. Downhole fluid analysis (DFA) can thus provide an additional source of information in the process of revealing complex reservoir architectures.


An accurate description of reservoir fluid properties is critical in all stages in the life of an oil or gas field. It is required in exploration to ascertain the true nature of a discovery and to assist in defining reserves to value the economic potential. In appraisal phase, it is used to determine layer connectivity and field structure as well as the optimization of well completion and production tests. For development of the field, fluid composition is crucial for material selection of well completion and surface flowlines, flow assurance, design of process control, and production facilities. Later during the exploitation of the reserves, it is necessary to understand fluid behavior during the production and life of the asset.

Reservoir engineering and production strategies are crucially dependent on knowledge of phase behavior and multiphase fluid flow, and they rely increasingly on numerical simulators tuned to pressure/volume/temperature (PVT) laboratory measurements. The presence of compositional gradients because of fluid migrations or fluids showing near-critical behavior at reservoir temperature must be understood to develop a valid model of the reservoir (Fujisawa et al. 2008).

Understanding the nature and composition of formation water is also critical to the economics of field development. Chemical analysis of formation or connate water determines the scaling and corrosion potential of produced fluid required for the design of completion and processing facilities (Raghuraman et al. 2007). It also establishes the salinity for petrophysical evaluation and fingerprints the aquifer for studies on basin hydrology. Water composition is important for production strategies involving inhibitor injection, wellstream mixing, process sharing, and enhanced-oil-recovery (EOR) injection.

Fluid sampling operations are continuously under pressure from cost control, operational limitations, and, sometimes, the lack of understanding of their true value in downstream processes. The risk of financial loss attached to poor fluid characterization, although difficult to quantify, can be enormous. This risk is magnified in deepwater projects, where the development can be extremely expensive and decisions on facility design must be made early in the project.

The type of reservoir fluid to be sampled has a considerable influence on the challenges encountered when sampling with WFTs. Near-critical systems are notorious for phase changes, which yield large proportions of both liquid and gas with only small reductions in pressure below the saturation curve. Because these proportions can exceed critical saturations, both fluids will be mobile to some extent, and the resulting production and samples may be difficult to interpret. If variations in sample properties are caused by contamination, these phenomena may not be identified until several wells have been appraised.

At the other extreme of the fluid range, hydrocarbons with very low gas/oil ratio (GOR) may cause separation and measurement problems or prevent proper collection of samples. Viscous oils can lead to high drawdown and plugging of sample lines, which require specialized sampling techniques and equipment. Emulsions may be formed, which make it difficult to collect a representative sample. Solids production, such as asphaltene deposition or wax formation, also affect fluid analysis with consequences on flow assurance in completions, pipelines, and surface facilities.

Water in hydrocarbon samples has traditionally been regarded as a contaminant, yet most hydrocarbon fluids naturally contain small quantities of connate water. Water concentrations can rise above 5% in high-pressure/high-temperature reservoir fluids. Understanding the effect of this water on phase behavior and fluid production becomes significant, but the issue is compounded by poor knowledge of actual concentrations in most reservoir fluids.

The presence of miscible contamination from the invaded filtrate of drilling fluids represents the largest obstacle to obtaining valid reservoir fluid samples. This occurs when sampling hydrocarbons in oil-based mud (OBM) and synthetic-oil-based mud (SOBM), or when sampling formation water in water-based mud (WBM). Miscible filtrate can severely affect the PVT fluid characteristics measured in the laboratory, and it results in inaccurate data for field development and reservoir modeling (Gozalpour et al. 1999). Mathematical techniques exist to back-calculate the uncontaminated fluid properties; however, these methods introduce additional uncertainties even when contamination is relatively low.

Fluid samples from WFT have been adversely affected by mud-filtrate contamination since their introduction. The first generation sampling tools consisted simply of a sample chamber connected by a flowline to the probe, which could be opened to collect a limited volume of near-wellbore fluid. Extremely high contaminations were common, and laboratory PVT analysis was not a viable option. This situation improved dramatically in the 1990s with the introduction of second-generation sampling tools, whereby a downhole pump was integrated into the flowline. This enabled fluid to be pumped from the formation to the wellbore during the "cleanup" while measuring contamination in real time with optical fluid analyzers to determine when flow should be diverted to the sample bottle. The configuration of modules in this tool string evolved over time to enable better control of filling sample chambers; however, the basic limitation regarding the interface between the tool and the formation still existed.

The rate of contamination decrease slows during the pump-out operation, and the level of contamination in the incoming fluid will not reach zero in any practical length of time (Mullins et al. 2001). The inability to reach zero contamination by invaded mud filtrate continually feeding the sampling zone from around the probe interface, and, in some cases, is caused by reinvasion of the sampling zone through the surrounding mudcake (see the section titled "'Discussion"). To achieve very low contamination levels, the WFT must usually engage in pump-out operations for extended periods of time, which can be expensive and risky in an openhole environment. In many situations, the only method to achieve uncontaminated samples has been through the large-volume cleanup associated with expensive drillstem tests (DSTs), and experience has shown that even these are not guaranteed to provide contamination-free fluid samples.

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