TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper presents a case study of a North Sea appraisal well where a large vertical fluid composition variation, missed by a conventional pressure gradient analysis method, was observed in situ in real time by a new fluid composition analyzer utilizing visible near-infrared (NIR) spectroscopy. For optimal oil production, it is as vital to assess the spatial variation of fluid properties as it is to assess the spatial variation of formation properties.Conventional wireline triple combo measurements showed the interval of interest was uniform and free from noticeable impermeable layers. A resistivity log showed an approximate oil/water contact. Wireline pressure testing identified three different pressure gradients corresponding to gas, oil, and water, all in hydraulic communication. However, the pressure testing did not indicate a gradient in hydrocarbon composition. Fluid was sampled and analyzed in real time by a wireline fluid sampling-analyzing toolstring that included the fluid composition analyzer. This tool analyzes petroleum fluid and gives concentrations for four group compositions (C 1 , C 2 -C 5 , C 6+ , and CO 2 ), gas/oil ratio (GOR), and qualitative information regarding heavy-end content and stock-tank crude density. The analyzer showed the hydrocarbon fluid in an oilbearing zone was not vertically homogeneous but instead had a large vertical variation. The samples captured by the wireline sampling tool were sent for a laboratory compositional analysis that confirmed the variation determined by the downhole analysis. Both results identified the heterogeneity of hydrocarbon fluid in the interval. This paper also covers briefly the measurement principle of the analyzer and discusses the impact and benefit the new technology brings. The concept of flexible fluid sampling is particularly important because it enables operators to make sampling decisions based on real-time fluid analysis results rather than a predetermined job plan.

TX 75083-3836 U.S.A., fax 01-972-952-9435. AbstractIn addition to geological and petrophysical data acquisition during the exploration stage, in-situ fluid analysis provides a wealth of information for the appraisal of new discoveries. A recently introduced wireline sampling tool incorporating a downhole fluid analyzer is capable of analyzing fluid composition in real time at downhole conditions, and of measuring the fluorescence spectra of crude oils. These new measurements provide valuable information necessary for the identification and validation of reservoir structures that define the distribution of fluids in the accumulation. The relevance of high quality fluid data in the early stages of the producing life of the reservoir is widely recognized. We present field results of the application of the new sampling tool in an exploration well, where a composition gradient was detected along a 30m liquid hydrocarbon column grading from a 45API crude on the top to a 33API crude on the bottom. During the sampling of the gas cap, retrograde dew formation was detected identifying the fluid and identifying valid sampling conditions. This new information was used to modify the sampling program. Fluid composition analysis relies on optical absorption methods and is currently capable of providing the mass fraction of three hydrocarbon molecular groups: C1, C2-5 and C6+, and CO2.We perform fluorescence spectroscopy by measuring light emission in the green and red ranges of the spectrum after excitation with blue light. Fluorescence in this range is related to the concentration of polycyclic aromatic hydrocarbons (PAH's) in the crude oil. Using the pump-out module to segregate different fluid phase enhances phase detection with fluorescence.

A new downhole pH sensor has been developed to provide an in-situ pH measurement of formation water at reservoir conditions, and results are presented for two wells in the Norwegian Sea. The measurement technique, for use with wireline formation sampling tools, uses pH-sensitive dyes that change color according to the pH of the formation water. To make a real-time pH measurement, the dye is injected into the formation fluid being pumped through the tool flowline, and the relevant visible wavelengths in an optical detector are used to record the dye signal and calculate pH with 0.1 unit accuracy. The pH of a formation fluid alters as the sample is brought to surface from the high temperature and pressure conditions downhole, owing to acid gases and salts coming out of solution and changes in water chemistry equilibria. To get an accurate pH, the measurement has to be made downhole at reservoir conditions. Unlike potentiometric methods where fouling of electrode surfaces by oil and mud is a potential problem, the dye technique is robust because the dye is isolated from the formation fluid and is injected into the sample only when a measurement is made. The technique has been successfully applied to both oil-based and water-based drilling muds, with successful measurements even in mixed oil/water flows. Multiple measurements of pH at a single sampling station demonstrate that the method is robust and repeatable. These measurements have been compared with numerical simulations using a multiphase chemical equilibrium model that uses laboratory analysis of collected water samples as input. pH is a key parameter in water chemistry and is critical for corrosion and scale studies. Accurate downhole pH measurement allows more accurate selection of appropriate completion materials and more effective planning for scale treatment and inhibition. Introduction The main objectives of formation water sampling in exploration wells are to obtain information regarding the scaling and corrosion potential of the water, understand reservoir connectivity, and establish the salinity of the water for petrophysical evaluation. Corrosion prediction is important for material selection for tubing, pipeline and process equipment, and scaling potential is an important parameter for the selection of an optimal development strategy. Correct water resistivity is important for interpreting openhole wireline logs accurately. In addition, analysis related to various environmental aspects like concentration of organic compounds and heavy metals in water is performed. Dissolved organic acids also affect water chemistry because they can influence the pH of the solution. Good quality formation-water data can improve the ability to make the right decisions early in development planning. These data can give information about compartments and communication in the reservoir. Later in the production cycle, these data can be used to differentiate produced connate water from aquifer or injection water breakthrough. Ideally, water samples from exploration wells should consist of representative, uncontaminated formation water, which can be difficult and costly to obtain. The quality of formation water data is highly dependent on the sampling technique and the type of drilling mud used in the reservoir zone. Oil-based drilling muds will usually give good-quality water samples because the mud filtrate is not miscible with water. Water-based mud filtrate can contaminate water samples because the filtrate is miscible with formation water, and chemical reactions can alter the true composition. The presence of sulfates in the mud, for example, may cause precipitation of barium in the formation leading to underestimation of barium and thus the scaling potential of the formation water.

The emergence of formation pressure measurements in the Logging-While-Drilling (LWD) market has highlighted the challenge of analyzing and interpreting the pressures acquired. The dynamic condition of the borehole and the freshly built mudcake add new variables to the problem and contribute in making the measurement more complex to interpret compared with measurements made by conventional wireline-conveyed methods. This paper presents several formation-pressure-whiledrilling case studies conducted in the North Sea. Formation pressure measurements were repeatedly performed under different well conditions and at different times after the bit penetrated the formation. The impact on the measurement of various parameters is analyzed, most notably, the time after drilling and changes in the measurement sequence. The results obtained with the formation pressure while drilling tool are compared to measurements performed with conventional wireline formation testers (WFTs) conducted at the same depths and at various times after drilling. Analysis of formation cores taken in the same intervals as the pressure tests were performed allows a better understanding of the while drilling-derived mobility measurements. Suggestions are made on how to improve the quality and accuracy of the measurements. Introduction Probe-type formation testers measure the pressure at the wellbore wall, the sandface, which, in oversimplified terms, is also the interface between the external mudcake and the formation. Fig. 1 is a sketch of this simplified view. Whether or not the pressure at the sandface is a good estimate of the true, far-field formation pressure depends on both the properties of the mud and the formation. If the filter cake is totally ineffective the formation tester will measure the wellbore pressure, whereas if the mudcake is perfectly sealing, given sufficient time, the tester should measure the true formation pressure. We are concerned here with the situation in which the mudcake forms a less than perfect seal allowing mud filtrate to leak into the formation resulting in a pressure drop from the sandface to the outer reaches of the formation. The radial change in pressure is primarily dependent on the sealing efficiency of the mudcake, the formation mobility and the difference between the wellbore and formation pressures. When the difference in pressure between the sandface and the formation pressure becomes significant, where the measure of significance depends on the application, the formation tester pressure is usually said to be supercharged. The degree to which the formation is supercharged is characterized by the overpressure, ?pS=psf-pf, where psf denotes the sandface pressure and pf represents the far-field formation pressure, (Fig. 1).1,2 Depending on the mud type and the reservoir fluids present, rock wettability and capillary pressure effects may also affect the sandface pressure measurement. It is not difficult to understand that the degree of supercharging depends at least on the history of the filtration rate from the moment the formation was first drilled, with the most recent history having the greatest effect, and, on the ability of the formation to accommodate the influx of filtrate, i.e., the degree of supercharging should be inversely related to the formation (total) mobility.2 Anything that inhibits the ability of the mudcake to seal the formation against filtration increases the supercharging effect; in particular, any action that limits the growth of mudcake or promotes the erosion of an established mudcake, such as, the scraping action of the bit and stabilizer blades and the mud circulation rate. It is known that even after a mudcake has had sufficient time to build to maximum resistance the ability to seal against invasion can be compromised by wiper trips.3

As we strive to complete more complex reservoirs, we are challenged to better understand the nature of the fluids contained within. In the North Sea, classical "black oils" are still encountered; however scenarios where volatile fluids that exhibit a bubble point are found in close proximity to fluids with dew points are not uncommon. In addition, knowing the CO2 content is paramount to completion engineering and facility design with high penalties incurred when CO2 quotas or production limits are exceeded. Characterizing these fluids is difficult. Typically wireline formation testers with fluid analyzers are used for early fluid characterization and sampling. However, with the increasing fluid complexity subtle differences need to be understood. This requires comprehensive compositional analysis, high resolution answers and quantified accuracy. This paper describes the technology and answers provided by an accurate in-situ fluid analyzer. Several case studies are discussed. In the first example oil is sampled from two depths, only a few meters apart. The in-situ fluid analysis data from these two depth, including C1, C2, C3-C5, C6+ CO2, GOR and density are compared, indicating excellent tool resolution. In addition these data are compared to laboratory sample analysis result with observed differences falling well within the quoted tool accuracies. A second example involves several closely stacked reservoirs. An in-situ compositional analysis was obtained for each reservoir fluid. By changing the flow rate of the formation tester downhole pump the flowing pressure was manipulated. This allowed to measure different ranges of bubble point pressures for each fluid. Only a few meters below a second fluid exhibiting a dew point was encountered. An indication of the fluid dew point pressure was detected by again manipulating the flowing pressure. Fluid analysis revealed compartmentalization and fluid grading through the different reservoirs in this well.