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Downhole Fluids Laboratory


Jefferson Creek Chevron Energy Technology Company Houston, Texas, USA


Myrt (Bo) Cribbs


Chevron North America Houston, Texas


Chengli Dong Oliver C. Mullins Houston, Texas


Hani Elshahawi


Shell International Exploration & Production Houston, Texas


Peter Hegeman Sugar Land, Texas


Michael O’Keefe Hobart, Tasmania, Australia


Kenneth Peters Mill Valley, California, USA


Julian Youxiang Zuo Edmonton, Alberta, Canada


Oilfield Review Winter 2009/2010: 21, no. 4. Copyright © 2010 Schlumberger.


For help in preparation of this article, thanks to Richard Byrd, Martin Isaacs and Michelle Parker, Sugar Land; and Dietrich Welte, Aachen, Germany.


Fluid Profiling, InSitu Density, InSitu Family, InSitu Fluid Analyzer, InSitu Fluorescence, InSitu pH, InSitu Pro, MDT and Quicksilver Probe are marks of Schlumberger.


1. For information on fluid sampling and DFA: Betancourt S, Davies T, Kennedy R, Dong C, Elshahawi H, Mullins OC, Nighswander J and O’Keefe M: “Advancing Fluid-Property Measurements,” Oilfield Review 19, no. 3 (Autumn 2007): 56–70.


Betancourt S, Fujisawa G, Mullins OC, Carnegie A, Dong C, Kurkjian A, Eriksen KO, Haggag M, Jaramillo AR and Terabayashi H: “Analyzing Hydrocarbons in the Borehole,” Oilfield Review 15, no. 3 (Autumn 2003): 54–61.


2. Hydrocarbons are defined as organic compounds comprising hydrogen and carbon. The simplest form is methane [CH4]. The most common hydrocarbons are natural gas, oil and coal. Petroleum, a form of hydro- carbon, is a term generally applied to liquid crude oil.


3. Muggeridge AH and Smelley PC: “A Diagnostic Toolkit to Detect Compartmentalization Using Time-Scales for Reservoir Mixing,” paper SPE 118323, presented at the SPE International Petroleum Exhibition and Conference, Abu Dhabi, UAE, November 3–6, 2003.


Organic material in source rocks is converted into the oil and gas that migrate into reservoirs. Variations in the composition of the original organic matter and the processes that occur dur- ing migration and accumulation of petroleum fluids often increase their compositional com- plexity. Once in place, reservoir fluids can equilibrate, yet still exhibit large compositional gradients. Frequently, however, fluids are in dis- equilibrium, disrupted by processes such as bio- degradation, multiple reservoir fluid chargings and seal breach. Downhole fluid analysis mea- surements, some of which have recently been introduced, can help resolve the complexity of these fluids at near-reservoir conditions. Armed with these data, asset managers can make informed decisions long before incurring huge expenses associated with field development and installation of production facilities. Although field development plans depend on a


thorough understanding of in situ properties, knowledge of the fluid characteristics alone is insufficient to maximize recovery. In particular, undetected barriers to fluid flow can create enormous problems for operators. For example, because pressure equilibration across sealing bar- riers can occur over geologic time, this equilibra- tion does not prove flow communication in production timescales. Failure to account for res- ervoir architectural complexity has often resulted in costly mistakes. New downhole fluid analysis


(DFA) technologies are available that enable iden- tification of reservoir compartmentalization and connectivity, along with fluid heterogeneities. To determine the fluid properties required for


effective reservoir development, engineers use DFA techniques extensively.1


properties are derived from a number of sensors, optical spectroscopy, based on visible and near- infrared (Vis-NIR) light, is the foundation of DFA measurements for hydrocarbons.2


Although fluid


Reservoir fluids rarely occur as simple liquids and gases filling monolithic structures. Their generation, migration and accumulation are affected by various processes that result in complex fluid compositions and distributions. In the past, failure to account for the complexities of the reservoir and its fluids has often resulted in costly production problems and disappointing results. Recent developments in formation testing and sampling technologies provide asset teams with a downhole laboratory to measure in situ fluid properties and gain insight into reservoir connectivity.


The technique


utilizes the light-absorption properties of fluids as well as light scattering from different materi- als to identify fluid composition (C1, C2, C3-5, C6+ and CO2), gas/oil ratio (GOR), relative asphal- tene content and water fraction. Other DFA mea- surements and capabilities include determination of pH and resistivity (if the fluid is water), index of refraction, fluorescence and live-fluid density. Prior to the availability of DFA measurements,


operators collected a limited number of samples, sent them to a laboratory and, after an often lengthy period of time, received a report describ- ing the reservoir fluids. Without real-time analysis to establish the extent of fluid complexity, ana- lysts often presumed fluid simplicity. Although the typical outcome was a simplified evaluation program, which initially appeared to be cost- effective, it came at the expense of adequate understanding of reservoir complexities. Too often the result was increased total project costs. With real-time DFA, the complexity and cost of


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Oilfield Review


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