Petroleum Exploration and Production in the Gulf of Mexico II
Presiding: D Patterson, HTC, Baker Hughes, Inc.; J Market, Halliburton Company
U42A-01 INVITED 10:30h
3D VSP imaging in the Deepwater GOM
Seismic imaging challenges in the Deepwater GOM include surface and sediment related multiples and issues arising from complicated salt bodies. Frequently, wells encounter geologic complexity not resolved on conventional surface seismic section. To help address these challenges BP has been acquiring 3D VSP (Vertical Seismic Profile) surveys in the Deepwater GOM. The procedure involves placing an array of seismic sensors in the borehole and acquiring a 3D seismic dataset with a surface seismic gunboat that fires airguns in a spiral pattern around the wellbore. Placing the seismic geophones in the borehole provides a higher resolution and more accurate image near the borehole, as well as other advantages relating to the unique position of the sensors relative to complex structures. Technical objectives are to complement surface seismic with improved resolution (~2X seismic), better high dip structure definition (e.g. salt flanks) and to fill in "imaging holes" in complex sub-salt plays where surface seismic is blind. Business drivers for this effort are to reduce risk in well placement, improved reserve calculation and understanding compartmentalization and stratigraphic variation. To date, BP has acquired 3D VSP surveys in ten wells in the DW GOM. The initial results are encouraging and show both improved resolution and structural images in complex sub-salt plays where the surface seismic is blind. In conjunction with this effort BP has influenced both contractor borehole seismic tool design and developed methods to enable the 3D VSP surveys to be conducted offline thereby avoiding the high daily rig costs associated with a Deepwater drilling rig.
U42A-02 10:45h
3C3D VSP Imaging of Salt Flanks Using Converted Waves in the Gulf of Mexico
Locating salt boundary and imaging updip sediment structures flanking the salt domes are very important tasks for exploration in the Gulf of Mexico since major petroleum reserves are often trapped underneath overhangs of diapiric salt domes. Although the top of salt and less steep structures can be well imaged using current surface seismic methods, the steep sides of a salt dome with irregularly shapes are hard to image with adequate accuracy. Thus, Vertical Seismic Profiling (VSP) surveys with three-component (3C) receivers in wells are usually requested for improving images of subsurface structures. Conventional multi-offset VSP (OVSP) and refraction salt proximity (SP) surveys are widely applied in the Gulf of Mexico to improve images of slat interfaces, sub-salt and salt flank structures using P waves. In this paper, we will focus on using converted waves to image the steep salt-sediment boundary. A VSP dataset, including multi-OVSP and a SP survey, acquired in the Gulf of Mexico was used in this study. We analyzed 3C OVSP data to identify and separate converted waves, such as PS, P-SP, P-SS, generated at a salt boundary. Then both PP wave and converted waves were 3C3D depth migrated to generate images of the steep salt-sediment interface. Both transmitted P-P and P-S converted waves from the SP survey were used to calculate 3D salt exit points which delineate the steep salt face. The VSP results derived from both methods are abundant and a suitable 3D visualization tool is required for visual integration and interpretation. The image volumes and other available geophysical and geological data were integrated using a 3D visualization tool specially designed for VSP solutions. The migrated images using PP and converted waves provides a precise and complete definition of the steep salt face and reservoir sands flanking the salt dome. This study indicates that both reflection and reflection surveys can result in a consistent location of the steep salt flank, demonstrating the strength of combining these advanced VSP techniques.
U42A-03 INVITED 11:00h
Acoustic Logging While Drilling
The acoustic velocities of sub-surface formations are critical in a number of analyses in the oil industry, ranging from borehole stability calculations that aid in drilling wells to formation evaluation and pore fluid identification. It has been possible for several decades to make reliable velocity measurements after drilling operations are complete. While post-drill analysis is valuable, there is a substantial benefit to being able to perform these calculations while drilling operations are ongoing. Real-time seismic ties, pore pressure estimation, and formation evaluation enable better planning and execution of expensive drilling and evaluation operations. Since the mid-1990's it has been possible to make compressional velocity measurements while drilling (MWD). The drilling environment presents many unique challenges to these measurements which impact tool design and data interpretation. The most recent MWD tools are adding the ability to estimate shear velocities. While shear logging is difficult in slow formations under any conditions, in the MWD environment there are additional complications beyond those encountered by wireline or compressional-only MWD tools. Shear velocity is an input into a variety of subsurface calculations. With current technology, we are forced to estimate this quantity when performing real-time evaluations. This necessarily makes the results questionable in cases where lithology and fluids are uncertain - precisely those situations we wish to evaluate. As MWD shear velocity estimates become more reliable and timely, these calculations will become more useful to oilfield operations. The potential of such improvements will be illustrated with a few examples.
U42A-04 11:15h
Sonic Data in Large, Shallow Holes
In the past, it has been difficult to acquire reliable data in large, shallow surface holes, as it is far from an ideal environment for wireline tools. With the advent of large (9 ") LWD sonic tools which do not need to be centralised and which log the formation mere minutes after drilling, it is possible, and in fact becoming common, to acquire good quality sonic logs almost from surface to bottom. Real time sonic pore pressure and compressional logs provide confidence in drilling and ties to seismic. There are some special considerations when logging in this environment, as the large fluid enhances certain borehole modes. Theory, modelling, and field data will be presented and discussed.
U42A-05 11:30h
Wireline and LWD Sonic data: Similarities and Differences
Wireline sonic data has been an integral part of the logging suite for many years, providing reliable compressional and shear data, along with a suite of applications such as Stoneley permeability, anisotropy and casing bond logs. More recently, LWD sonic logs have become an increasingly common component of the drill string. Whereas the many similarities of the data allow for substitution of LWD for wireline in many situations, there are also differences in the measurements due to the inherent differences in the environment. Perhaps the most under-appreciated difference is exposure time. The LWD data is generally acquired only minutes behind the bit, while wireline data is often acquired many hours or even days after drilling. This time difference can lead to differences in velocities, as the LWD tools are seeing more pristine (less degraded) formations than wireline. The exposure time differences can actually be very useful information if logs are acquired at multiple times. Other differences between wireline and LWD include slow shear measurements, centralisation, and telemetry issues. We will review some of these similarities and differences in detail, showing modelling and field data for several wells.
U42A-06 11:45h
Acoustic Anisotropy Measurement and Interpretation in Deviated Wells
A current trend in petroleum exploration and production is that more and more deviated/horizontal wells are drilled, especially in deep water reservoirs like Gulf of Mexico. The issue of anisotropy is particularly important for deviated wells penetrating the soft sedimentary rocks of the reservoirs. In sedimentary formations, shales can be highly anisotropic due to mineral alignment, and sands can also be anisotropic due to their sensitivity to formation stresses. Many acoustic anisotropy measurements using cross-dipole tools have been made in deviated wells. However, interpreting the acoustic anisotropy data can be quite complicated, especially in the presence of strong anisotropy. In a deviated well, the well trajectory is neither perpendicular to, nor parallel with, the formation bedding planes. Consequently, the measured anisotropy is not the true formation anisotropy, but an apparent anisotropy at a given well deviation. Besides, several anisotropy parameters (e.g., Thomsen parameters) are needed to characterize the formation anisotropy while the cross-dipole measures only one of them. Nevertheless, the variation of the anisotropy and its associated azimuth relative to the well trajectory contains the information about the anisotropy parameters. By analyzing the anisotropy data in conjunction with the well configuration, we can characterize the relationship among the anisotropy parameters. By combining the data with lithology, we can also distinguish stress-induced anisotropy from other sources of anisotropy. The result is an improved characterization of formation anisotropy and its geological environment.