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ABSTRACT Recent developments in surface logging and the need for sophisticated information on reservoir content and type in the oil industry have led to the availability of real-time advanced fluid solutions assisting in informed decisions while drilling. The objective of this study was to identify possible fluid contacts and acquire PVT quality sample data while drilling Paleozoic formations. This is accomplished by extracting and analysing formation gas from the drilling fluid employing the Advanced Formation Gas Extraction System for formation evaluation with a high-resolution chromatograph. The Advanced Formation Gas Extraction System provided consistent flow and heated mud and maintained constant temperature conditions. Thus, it provided an accurate chromatographic breakdown of the formation gas extracted from the drilling fluid at surface. The chromatograph was able to detect the hydrocarbons from the light to heavy factions, methane (C1) to pentane (C5), and also extended the detection range to include the dominant C6, C7, C8, aromatics and lighter alkenes. Gas ratio analysis of the detected hydrocarbon components enabled us to evaluate the reservoir fluid content and to identify and characterize the formation fluid and possible fluid contacts. The results, validated by correlation and comparison with other data such as wireline logs, well tests and PVT results assisted in the characterization of lithological changes, possible fluid contacts, vertical fluid differentiation in multi-layered intervals, and drill bit metamorphism (thermal cracking) effect. The comparison between surface gas data analysis and PVT data confirms the consistency between the gas show and the corresponding reservoir fluid composition.
Abstract Acquisition of representative rock and fluid data from deepwater reservoirs is challenging and costly but is critical for the successful reservoir evaluation. It is common practice to use oil based mud, OBM, for drilling, particularly in deepwater offshore environment. Without proper mud additives and under excessive overbalance, OBM often invades the reservoir and contaminates cores and fluids. Measurements conducted on contaminated samples result in non-representative rock and fluid properties. Therefore, every effort should be made to minimize contamination in the samples. In fluids, mathematical corrections are needed to remove contamination effect and ensure representative fluid properties. In rocks, measurements on samples with minimum contaminations should be validated with those on cleaned samples. High OBM invasion in several cores showed elevated apparent in-situ water saturation as identified by visual examination, CT density mapping, residual brine analysis, and total liquid saturation calculation. Electrical resistivity measurement on "as-received" samples and simultaneous capillary pressure and resistivity measurements on cleaned samples provided correct in-situ water saturation determination. Customized sampling procedures with reliable fluid quality monitoring helped obtain minimally contaminated samples. In addition, novel mathematical techniques allowed correcting fluid samples to calculate representative fluid properties. Field examples are provided to demonstrate the success of these techniques for improved rock and fluid characterization. The results of this study demonstrate the need for reservoir engineers to be closely involved in fluid sampling, coring, and data acquisition stages employing rigorous QA/QC protocols. Customized sampling and coring programs were essential to obtain minimally contaminated rock and fluid samples and rigorous methodologies were critical to correct the data measured on the contaminated samples and determine representative rock and fluid properties.
This paper is presented as a summary report of the use of well gas composition correlations obtained from mass spectrometer recordings as a means of identification and determination of reservoir continuity.
Conventional methods for detecting composition differences are expensive, elaborate, and difficult to obtain. This excludes the use of extensive composition data for most applications.
During recent years the mass spectrometer has come into general use as an analytical tool in petroleum refineries. The use of mass spectrometer composition patterns in characterizing or "finger-printing" the produced gas from a reservoir, presents a novel method for correlating gas samples from well to well. The mass spectrometer provides a trace similar to an electric log, having peaks which represent the abundance of certain hydrocarbons in the well gas sample. Without going further into the detailed analysis, the idea has been advanced that these traces or patterns could be used as a means of identifying a particular natural gas. This theory has proven to be essentially correct. The mass spectrometer pattern method is simple and cheap as compared to other standard methods. It greatly facilitates the solution of reservoir and geological problems in which correlation of well gas compositions is a factor.
Specific field applications have been made. This paper concerns the results obtained in 465 individual gas analyses from 35 fields and 77 reservoirs. In a number of cases it has been found that such data have been extremely valuable in the determination of reservoir continuity. In at least one case, the method was a valuable contribution in tracing a reservoir from sand to sand in a complex faulted field involving numerous gas reservoirs.
Field applications are presented to illustrate the possibilities of the method at the present stage of development and to stimulate the employment of this new approach by geologists and petroleum engineers in the industry.
The inversion of chemical data to meaningful mineralogical assemblages provides a quantitative basis for the prediction of petrophysical parameters. The most valuable transforms attempt to provide the proportions of actual mineral phases present (solids and fluids) at each depth interval rather than ideal minerals occurring in theoretical models (norms). Compositional colinearity, in which three or more of these phases lie on, or close to, the same compositional plane is a most serious problem. Depending on the algorithm used for the inversion the effects of these compositional constraints may vary between a failure to find any numerical solution, failure to find a unique solution, or a solution which may be significantly in error. These effects are illustrated for sedimentary environments using well-constrained laboratory geochemical and mineralogy data. Introduction With the development in recent years of the Geochemical Logging Tool (GLT), by Schlumberger, comes the ability to determine the absolute abundance of nearly all the major chemical elements that make up common rocks.
Navarrete, J.. (Schlumberger) | Gordon, C.. (Schlumberger) | Garcia, M.. (Schlumberger) | Bolanos, M. J. (Schlumberger) | Vega, J.. (Schlumberger) | Lafournere, J. P. (Schlumberger) | Naranjo, M.. (Schlumberger) | Paladines, A.. (Schlumberger) | Bourge, J. P. (Schlumberger) | Suter, A.. (Schlumberger) | Henson, R.. (Schlumberger) | Delgado, P.. (Schlumberger) | Fornasier, I.. (Schlumberger) | Morales, O.. (Petroamazonas EP) | Badillo, V.. (Petroamazonas EP)
Abstract The Oriente Basin is located in eastern Ecuador at the Amazon rainforest. Shushufindi-Aguarico field is one of the most important fields in Oriente Basin with over 12% of the national production; the main hydrocarbon reservoirs are located inside the Cretaceous formations Napo and Tena. In spite of being a mature field in production since the beginning of 1970s, Shushufindi-Aguarico field still presents various formation evaluation challenges that can potentially be explored to enhance its productivity. In order to improve fluids characterization in a recently developed area at NorthWest of the field, a new reservoir evaluation technology, Fluid Logging and Analysis in Real Time, is introduced to obtain a continuous log of quantitative composition of hydrocarbon and an improving in the pay zones analysis from gas presence in the mud while drilling. The prospective intervals determination within the productive reservoirs is performed while drilling with cuttings analysis and chromatography evaluation in real time. This evaluation is based on Gas Ratio Method, which uses the relation between heavy, medium and light gases to identify porous rocks with hydrocarbon presence. The prospective intervals determination using Advanced Surface Fluid Logging technology gives more precision to identify thin beds by eliminating the recycled gas effect than conventional mud logging. In addition, the Advanced Surface Fluid Logging provides fluid composition in the C1-C5 range analogous to the PVT single phase composition. The fluid composition achieved in the main target zone exhibited a close correlation with a convention PVT from a recent offset well. This paper presents a case study where ASFL technology was tested on a Shushufindi well highlighting valuable benefits, with better pay zones definition in the challenging geological environments encountered in the Shushufindi-Aguarico field. The reliability of the data provided is demonstrated by the good correlation amongst the Fluid Logging and Analysis in Real Time composition recorded in the main target zone and a recent PVT composition from a nearby offset well.