Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Fluid Characterization
Is There A Better Way to Determine The Viscosity in Waxy Crudes?
Daungkaew, Saifon (Schlumberger) | Fujisawa, Go (Schlumberger) | Chokthanyawat, Suchart (Schlumberger) | Ludwig, John (Chulalongkorn University) | Houtzager, Fred (Mubadala Peroleum) | Platt, Christopher (Mubadala Peroleum) | Last, Nick (Mubadala Peroleum) | Limniyakul, Theeranun (Mubadala Peroleum) | Phaophongklai, Wattanaporn (Mubadala Peroleum) | Comrie-Smith, Nick (Salamander Energy) | Thaitong, Thanagit (Salamander Energy)
Abstract Accurate viscosity measurement is difficult even under the best of conditions and the lengthy time required to send and receive results from a lab prohibit basing important decisions on the viscosity of the reservoir fluid. Those challenges increase for reservoirs with complex fluids such as the highly viscous, waxy crudes found in many of the oil fields in South East Asia. While correlations have been developed to determine the viscosity of waxy crudes, the accuracy can be limited under certain conditions. The objective of the paper is to review visc sity correlations for waxy crude and examine their applications to the actual field data. Limitations on the use and accuracy of these correlations will then be discussed. This paper also discusses the viscosity obtained in real-time from the suite of Downhole Fluid Analysis (DFA) measurements, and the result is then compared to standard PVT analysis over a wide range of viscosities, temperatures, and pressures. Results of the DFA viscosity measurements in several fields in South East Asia are discussed together with other fluid properties such as GOR, density, and fluid compositions. The viscosity is then examined at the field scale to help understand the reservoir complexity in terms of compartmentalization in these waxy oil environments. The technical contribution from this paper is that it presents the variation of the viscosity in waxy oil reservoirs and its impact on real time decision making, especially for purposes of pressure transient analysis. This paper covers the evolution of the DFA viscosity measurement including a description of the hardware, discusses the limitation of the DFA measurement for certain conditions, and summarizes the accuracy of the DFA viscosity measurement for different fluids and the ongoing development for covering more fluids in the lower end of the viscosity spectrum.
- Asia > Middle East (0.93)
- North America > United States (0.68)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
Examples of Advanced Technologies/Methods Applied in Challenging Wireline Formation Tester Environment to Better Characterize Reservoir Fluid Distribution
Cardoso, Elmer (Sonangol P&P) | Santos, Celia (Sonangol P&P) | Crowe, John (CABGOC) | Stockden, Ian (BP Angola) | Vervest, Edwin G. (BP Angola) | Dorman, James (Angola LNG) | Guivarch, Benoît (Total EP Angola) | Nsingui, Gabriel (Total EP Angola) | Daniele, Nicola (Eni Angola) | Pentoli, Italo (Eni Angola) | Kin, Khong Chee (Schlumberger) | Zuo, Julian (Schlumberger)
ABSTRACT Representative formation pressures and fluid samples are critical to characterize reservoir fluid distribution, contacts, permeability and for compartmentalization evaluation. High mud overbalance, imperfect mudcake or long borehole exposure to drilling mud results in deep invasion requiring long clean up during fluid sampling to obtain high purity formation fluid. Oil based mud filtrate is miscible with hydrocarbon and accurate fluid identification and clean up estimation during sampling has to integrate various insitu fluid measurements for representative fluid sampling. High mud overbalance results in deep invasion that requires high pressure pumps and focus sampling method to successfully obtain samples with low contamination. In low permeability formation, pumped volume could be low for allowed station time. This requires reservoir fluid properties to be inferred from insitu analysis of fluid with high mud filtrate contamination; ratio fluid analysis can complement insitu fluid composition to better characterize fluid at high mud filtrate contamination. Often times fluid gradient could not be inferred from pressure due to insufficient number of pressure points or low quality of acquired pressure data due to supercharge of partial sealing effects. Insitu fluid density helps to enable contacts derivation in these conditions. Insitu fluid viscosity also could also be obtained to characterize fluid viscosity and derive permeability from wireline formation tester and well test interpreted mobility. Compositional and fluid density grading could be identified using excess pressure technique. Excess pressure analysis can be supported by gradient analysis. Asphaltenes are now being modeled from first principles and are frequently shown to exist in complex gradients, factors that give rise to fluid complexities include current/multiple reservoir charging, biodegradation, water/gas washes, and leaky seals. Asphaltenes gradient can also be used to complement pressure for vertical compartmentalization and lateral continuity analysis. Efficient probe pretesting tool with capability to perform multiple small volume pretests provide higher pretest success rate in low permeability formation or in depleted reservoir. At borehole condition when probe could not attain good seal, obtain representative formation pressure or sample representative formation fluid, dual packer can be used in openhole or inside casing after perforating the interval to be tested.
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- (2 more...)
ABSTRACT: What are the advantages and where are the limitations of fluid analysis and sampling while drilling tools? There are currently two main questions that are discussed in the community. Will it be possible to achieve the same sample quality with one of the new fluid analysis and sampling tools for while-drilling applications as with currently available wireline technology? And will it be possible to achieve this after a shorter pump-out time? Multiple simulations were performed to see if it is beneficial to take samples as early as possible after the drilling process, or if it is beneficial to have a completely formed mud cake. In this paper the different aspects of this query will be discussed by a case study. Compared to the widely used wireline formation testing tools, the first generation of logging while drilling tools is equipped with less complex measurement technologies. This is due to the rough drilling environment, where the very sensitive measurement technology and actuator systems have to be protected more carefully. The limited measurement technology is mainly used for clean-up estimation rather than for fluid identification. Current measurement technologies besides pressure and temperature in sampling while drilling tools are density, viscosity, sound speed and refractive index, but are not limited to these. On the other hand, a much more sophisticated pump and pump control system is necessary due to the slow surface communication via mud pulse telemetry. A closedloop control system and different intelligent algorithms avoids pumping below the bubble point and thus the alteration of the fluid sample. The build in computing power of the tool itself needs to be much higher for the complex control of the pump and measurement technologies. This gives the operator more freedom to monitor and interpret the sensor readings.
- Europe > Netherlands (0.68)
- North America > United States > Colorado (0.29)
- North America > United States > Texas (0.28)
Abstract The first formation testing tools were introduced as wireline tools in the 1950s. Since then, many technological steps were achieved, starting with simple sampling devices adding different measurement technologies in the 1980s up to formation pressure while drilling (FPWD) tools introduced to the field in 2000. Over the last 20 years wireline technology evolved towards high-quality single-phase sampling that also led to the development of the first formation sampling while drilling (FSWD) tools being introduced just over a year ago. In this paper we present a new fluid analysis and sampling tool designed for logging while drilling (LWD) applications. As it is built on the widely proven FPWD technology, it includes all its functionality of optimized testing and seal control. This service operates using a closed-loop control system, integrates real-time downhole analysis of the pressure data, and provides a repeat pressure test with an optimized rate control based on the in-situ derived mobility. This is made possible by the highly accurate pump control system employed. In addition to pressure and mobility capabilities the fluid analysis and sampling tool can analyze and obtain formation fluid samples. The new tool is equipped with high-power pump-out capabilities and highly sophisticated sensors to measure the optical refractive index, the sound speed, the density and the viscosity of the fluid. The innovative pump control prevents alteration of the fluid sample by avoiding pumping below the bubble point. The tool employs the same sample tanks that are used in our wireline tools. The tanks are approved by the Department of Transportation (DOT) for direct transportation of a sample to a certified pressure-volume-temperature (PVT) lab without transferring the sample into another sample bottle. The tool can collect and preserve up to 16 single-phase samples at surface pressures up to 20,000 psi in a single run. It uses a nitrogen buffer system to ensure the suffienct pressure is applied to the sample to prevent alteration. In this paper the capabilities of this new LWD fluid analysis and sampling tool and its first field application on a land rig in Oklahoma are be shown. The field results are compared with a wireline results run to prove the concept of shorter clean-up times while sampling soon after the formation is penetrated by the drill bit. An outlook will be given how to apply this new technology in future applications.
- Europe (0.88)
- North America > United States > Texas (0.46)
- North America > United States > Oklahoma (0.34)
- Well Drilling > Drilling Measurement, Data Acquisition and Automation > Logging while drilling (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Formation test analysis (e.g., wireline, LWD) (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)