Pressure Measurement and Pressure Gradient Analysis: How Reliable For Determining Fluid Density and Compositional Gradients?
Abstract: TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractPressure-depth plots have been used for over thirty years to evaluate fluid density, fluid contacts, and pressure compartmentalization in formation tester pressure surveys. However in the Niger Delta region and other offshore deepwater environments, many reservoirs are multilayered and highly variable in terms of connectivity, permeability and fluid properties. Such complexity and reservoir heterogeneity means conventional pressure-depth plot and pressure gra… Show more
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Cited by 8 publications
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Knowledge of formation fluid density is necessary for a variety of applications. It provides information on pressure gradient, zonal compartmentalization, transition zone characterization, thin beds analysis, and other reservoir qualities. It also contributes to estimates of the commercial value of the produced fluid and is a critical parameter used in modeling of the reservoir fluids through the equation of state (EOS) to obtain a better representation of fluid Pressure/Volume/Temperature (PVT) properties. Various techniques exist today for the measurement of formation fluid density. These measurements can be taken either at surface on captured fluid samples or downhole in real time using formation tester tools. The different techniques include laboratory PVT analysis of a fluid sample brought to surface, pressure gradients, downhole optical spectroscopy, and, recently developed, density measurements with the in-situ densimeter, which determines density by measuring the resonance characteristics of a vibrating object immersed in the fluid. Although PVT analyses have excellent accuracy, downhole measurements have an advantage over surface measurements as they provide in-situ measurements under reservoir conditions without depending on the quality of the fluid from the sample bottle and sample transfer. They also allow better reservoir characterization without the need for an extensive sampling program. Pressure gradient surveys have been successfully used for decades to provide density measurements of the formation fluids. Although the measurement depends on the accuracy of both pressure measurement and depth, it provides density unaffected by flowline condition of formation testers and mud filtrate contamination. Downhole flowline sensors, such as spectroscopic sensors and vibrating rods, have the advantage of providing density measurements of the fluid itself rather than relying on other parameters such as depth, but they are sensitive to flowline conditions. Whereas the estimation of density from the spectroscopic method relies on an empirical model that cannot be used in every condition, the vibrating rod in-situ density sensor gives a direct physical measurement and is thus the preferred method of measurement whenever available. Introduction Precise fluid characterization provides vital information for reservoir evaluation, flow assurance, facility design, reservoir management, production strategies and reserves definition. Many applications benefit from a precise knowledge of the formation fluid density. Measurements are performed by various techniques at surface or downhole, where some can be intercorrelated to enhance reservoir characterization. Surface measurements include PVT analysis on the formation fluid samples at the wellsite or in a laboratory. Downhole measurements include pretest pressure surveys, molecular spectroscopy measurements and in-situ flowline measurements with vibrating object densimeters. These results are then used for the fluid gradient determination, thin bed analysis, reserve estimation, fluid modeling, zonal connectivity, compositional gradients, contamination estimation, transition zones, compressibility, etc.
Knowledge of formation fluid density is necessary for a variety of applications. It provides information on pressure gradient, zonal compartmentalization, transition zone characterization, thin beds analysis, and other reservoir qualities. It also contributes to estimates of the commercial value of the produced fluid and is a critical parameter used in modeling of the reservoir fluids through the equation of state (EOS) to obtain a better representation of fluid Pressure/Volume/Temperature (PVT) properties. Various techniques exist today for the measurement of formation fluid density. These measurements can be taken either at surface on captured fluid samples or downhole in real time using formation tester tools. The different techniques include laboratory PVT analysis of a fluid sample brought to surface, pressure gradients, downhole optical spectroscopy, and, recently developed, density measurements with the in-situ densimeter, which determines density by measuring the resonance characteristics of a vibrating object immersed in the fluid. Although PVT analyses have excellent accuracy, downhole measurements have an advantage over surface measurements as they provide in-situ measurements under reservoir conditions without depending on the quality of the fluid from the sample bottle and sample transfer. They also allow better reservoir characterization without the need for an extensive sampling program. Pressure gradient surveys have been successfully used for decades to provide density measurements of the formation fluids. Although the measurement depends on the accuracy of both pressure measurement and depth, it provides density unaffected by flowline condition of formation testers and mud filtrate contamination. Downhole flowline sensors, such as spectroscopic sensors and vibrating rods, have the advantage of providing density measurements of the fluid itself rather than relying on other parameters such as depth, but they are sensitive to flowline conditions. Whereas the estimation of density from the spectroscopic method relies on an empirical model that cannot be used in every condition, the vibrating rod in-situ density sensor gives a direct physical measurement and is thus the preferred method of measurement whenever available. Introduction Precise fluid characterization provides vital information for reservoir evaluation, flow assurance, facility design, reservoir management, production strategies and reserves definition. Many applications benefit from a precise knowledge of the formation fluid density. Measurements are performed by various techniques at surface or downhole, where some can be intercorrelated to enhance reservoir characterization. Surface measurements include PVT analysis on the formation fluid samples at the wellsite or in a laboratory. Downhole measurements include pretest pressure surveys, molecular spectroscopy measurements and in-situ flowline measurements with vibrating object densimeters. These results are then used for the fluid gradient determination, thin bed analysis, reserve estimation, fluid modeling, zonal connectivity, compositional gradients, contamination estimation, transition zones, compressibility, etc.
Modern formation pressure testing while drilling (FPWD) tools provide accurate formation pressure measurements, even under very challenging drilling and formation testing conditions. Pressure data from logging while drilling (LWD) tools are primarily used for drilling safety related pore pressure profiling, mud weight optimization and ECD controls. Its full potential in formation and reservoir evaluation has yet to be further explored. Pressure gradient analysis is a particularly costeffective solution for preliminary reservoir fluid evaluations while drilling or shortly after the well is drilled. Integrated with other LWD and surface logging data, pressure gradient analysis is able to provide valuable insight for planning subsequent fluid sampling, well completion and reservoir development programs which require accurate assessments of fluid types, fluid contacts, reservoir compartmentalization, and connectivity. Based on data and experience from recent worldwide FPWD and gradient jobs, we present a recommended best practice workflow for pressure gradient analysis using real time pressure testing data. The main procedures of the workflow consist of pre-job preparation, real time wellsite execution, quality control, statistics and error analysis, proper graphic presentation, data integration and interpretation. Special effort is made to identify fluid types, contacts, vertical fluid variation and reservoir barriers from pressure gradient analysis. It is found that the integration of pressure data with openhole logs and surface mud gas logging is particularly effective in reducing uncertainties in the interpretation. Possible factors responsible for departure from linear pressure gradient trend lines are discussed together with the limitations of gradient analysis. Quick reservoir evaluation in terms of fluid types, oil water contact (OWC), oil gas contact (OGC) and flow barriers can be obtained independently with the use of pressure gradient analysis from FPWD data. More reliable results are achieved by the integration of pressure measurement data with the openhole log interpretation, surface logging and offset well information collected in the pre-well planning stage as well as while the well is being drilled. Introduction For several decades, the pressure gradient plot has been used for identifying reservoir fluid types, contacts and reservoir connectivity (Chen, 2003; Steward et al., 1979, 1982). The information obtained from pressure gradient analysis has contributed to improved reservoir characterization and optimized completion and production strategies. Vast majorities of previous gradient work have been carried out with data from wireline formation pressure testing data and production logging tools (PLT). In recent years, increased usage of LWD formation pressure testing has broadened the spectrum of available raw data for pressure gradient analysis (Meister et al., 2003, 2004; Buysch et al., 2005).
Low-permeable reservoirs have long been recognized as a challenge for economical production. Characterization of complex carbonate reservoirs exhibits some special challenges. Pay zones may be poorly defined due to marginal reservoir properties, i.e., uncertainties regarding the distribution of oil on the pore scale and the ability of oil to flow at high initial water saturation. Hence, the oil water contact may not be a precise level in the reservoir and the vertical span of the oil-water transition zone may be greater than 100 meters in such reservoirs. The traditional reservoir engineering approach defines free water level and hence the water- and oil-zones from the oil- and water pressure gradients. Pressure gradients are, however, difficult to obtain in low-permeable media and it has been reported that supercharging effects may be the result of mobile oil and water at the same place in the reservoir. A case study is made for an offshore exploration well in a complex and heterogeneous carbonate oil reservoir. The well is not production tested and gives a clear water gradient. However, there is indication of relatively high oil saturation with possible live oil properties. This is not typical for a reservoir that has been completely water washed during historical time. Different initial fluid distributions are studied in simulation of filtrate invasion in order to explain the observations in the exploration well. The results are of general interest, with application to many low-permeable reservoirs. This work gives new insight into the important interplay between type of drilling mud, reservoir wettability and interpretation of fluid gradients. The novel implication of the results is that a water-gradient is measured in the transition zone if an oil-wet reservoir is drilled with water-based mud. A water gradient can therefore exist even though the oil saturation is high. The shift between the water gradient and oil gradient occurs when mobile oil is present in water-wet pores giving a positive oil-water capillary pressure. Introduction The fluid distribution in oil reservoirs reflects the accumulation history and hence chemical, biological and geological processes during millions of years. The complexity of such processes seems to be significantly and the outcome difficult to predict. However, by experience it is known that some simple physical laws may adequately explain today's water and oil saturation without detailed knowledge of the accumulation history during millions of years. The main assumptions made for practical engineering purpose are i) the equilibrium between gravity and capillarity; and ii) the oil has originally migrated into a water-wet environment. The initial conditions in a homogenous reservoir with high permeability can therefore most often be described easily from the primary drainage process and the reservoir divides into clearly defined oil and water zones. Hence, water is the only mobile phase in the water zone and oil is the only mobile phase in the oil zone. The initial fluid mobilities are thus a matter of single phase flow with possible modifications for the connate water saturation or the residual oil saturation (if paleo oil is present). Fluid gradients will reflect the mobile phase and capillary pressure effects on the gradient can be neglected. The most common reservoir engineering interpretation of fluid gradients is accordingly that an oil gradient implies producible oil and a water gradient implies either 100% water saturation or in some special cases water and residual oil saturation (paleo zone). This is most often supported by the petrophysical evaluation with a rapid change in resistivity at the oil-water contact (OWC). The free water level (FWL) is per definition the position where the oil-water capillary pressure is zero and is estimated to be where the extrapolated oil and water gradients do cross.
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