Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
Downhole Viscosity Measurement: Revealing Reservoir Fluid Complexities and Architecture
Mishra, Vinay K. (Schlumberger) | Barbosa, Beatriz E. (Schlumberger) | LeCompte, Brian (Murphy Oil) | Morikami, Yoko (Schlumberger) | Harrison, Christopher (Schlumberger) | Fujii, Kasumi (Schlumberger) | Ayan, Cosan (Schlumberger) | Chen, Li (Schlumberger) | Dumont, Hadrien (Schlumberger) | Diaz, David F. (Schlumberger) | Mullins, Oliver C. (Schlumberger)
Abstract Knowledge of formation fluid viscosity and its vertical and lateral variations are important for reservoir management and determining field commerciality. Productivity and fluid displacement efficiency are directly related to fluid mobility, which, in turn, is greatly influenced by fluid viscosity. Therefore, viscosity is a critical parameter for estimating the economic value of a hydrocarbon reservoir and also for analyzing compositional gradients and vertical and horizontal reservoir connectivity. The conventional methods for obtaining formation fluid viscosity are laboratory analysis at surface and pressure/volume/temperature (PVT) correlations. However, deducing viscosity from correlations introduces uncertainties owing to the inherent assumptions. Surface viscosity measurement may be affected by irreversible alteration of the sampled fluid through pressure and temperature changes, as well as related effects of long-term sample storage. A new downhole sensor for a wireline formation tester tool has been introduced to measure the viscosity of hydrocarbons. The new viscosity sensor uses a vibrating-wire (VW) measurement method with well-established analytical equations for interpretation. Downhole field testing of an experimental prototype has been conducted, with extensive laboratory tests to validate the sensor performance in viscosities ranging from light to heavy oil and at a wide range of well environments. The vibrating wire viscometer sensor meets requirements not only for measurement performance, but also for operations in downhole applications, and possesses the following properties:
- Asia > Middle East (0.93)
- North America > United States > Texas (0.68)
- Africa (0.68)
- South America > Atlantic Basin (0.89)
- North America > Atlantic Basin (0.89)
- Europe > Atlantic Basin (0.89)
- Africa > Atlantic Basin (0.89)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (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)
- (3 more...)
Reducing OOIP Uncertainty In HPHT Environments With Improved-Accuracy Formation Pressure Measurements
Dumont, Hadrien (Schlumberger) | Gisolf, Adriaan (Schlumberger) | Hows, Melton (Shell) | Dong, Chengli (Shell) | Chen, Hua (Schlumberger) | Barbosa, Beatriz E. (Schlumberger) | Chen, Li (Schlumberger) | Emanuel, Victor (Schlumberger) | Pfeiffer, Thomas (Schlumberger) | Mishra, Vinay K. (Schlumberger) | Ayan, Cosan (Schlumberger) | Achourov, Vladislav (Schlumberger)
Abstract Pressure gradients are routinely used to determine fluid contacts. The accuracy of static formation-pressure measurements directly affects the estimation of original oil in place (OOIP). Depth errors, pressure gauge accuracy, gauge temperature sensitivity, gradient-fitting errors, capillary pressure, and compositional gradients are among the most prevalent sources of uncertainty. Most of them are well documented at lower temperatures and pressures, but, until now, fluid contact uncertainty in high-pressure, high-temperature (HPHT) environments has received little attention. Formation testing pressure gauges are subject to a constantly changing temperature environment. Most gauges are temperature calibrated, but they often struggle to account for changes in temperature. This is particularly true in HPHT environments, where pressure and temperature are currently measured by different sensors. This leads to large and unrecognized measurement error. Additionally, the gauges' specified accuracy is relatively low because the calibration covers a wide range of temperature and pressure. Such errors accumulate when multiple gauges are used in multiwell gradient extrapolations. Reduced dynamic response, repeatability, and stability further decrease the performance of today's HPHT gauges. The resulting errors in fluid contact measurements in HPHT environments, which could be hundreds of feet, lead to billions of dollars of variation in reserves. A new gauge technology addresses many of these potential errors, with specific application to HPHT environments. When pressure and temperature are measured by a single crystal, we will refer to as single-crystal dual-frequency-mode or dual-mode. The simple design of the new single-crystal dual-frequency-mode gauge increases the maximum pressure and temperature limits. The overall size of the gauge is reduced, which shortens its thermal dynamic equilibrium time. The stress-balanced and temperature-compensated dual-rotation cut angle of the resonator design concurrently allows operations at high pressure and temperature. In a temperature range between 200° F and 392° F at 15,000 psi or pressure up to 30,000 psi at 365° F, the gauge achieves 2 psi sensor accuracy, and 0.008 psi resolution.
- South America (1.00)
- Europe (1.00)
- Africa (1.00)
- (2 more...)
- Geophysics > Borehole Geophysics (0.73)
- Geophysics > Seismic Surveying (0.47)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > HP/HT reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Estimates of resource in place (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)