Saudi Arabian Oil Company

Schlumberger Technology Corporation

Saudi Aramco Oil Company

Aramco Services Company

Edward Alan Clerke

Patrice Ligneul

Raghu Ramamoorthy

Roger R Sung

David Furse Allen

Philip M Singer

Steve F Crary

George Bordakov

Ramsin Yacood Eyvazzadeh

Johannes J M Buiting

Paul Smith

Jim Funk

Philip Savundararaj

Johannes J Buiting

Aqeel M Khalifa

An approach for reservoir characterization is based on rock geochemistry of the subterranean formation. This approach includes: collecting rock samples related to lithostratigraphy of target wells; measuring geochemical/ mineralogical parameters of the rock samples; measuring geochemical/mineralogical parameters of the subsurface formation; measuring formation acoustic velocities for the target wells; generating characteristic rock sample and log signature patterns for different lithostratigraphic layers based on the measured geochemical/mineralogical parameters and acoustic velocities associated with the different lithostratigraphic layers identified in the target wells; combining the characteristic log signatures for the different lithostratigraphic layers into a lithographic interpretation using neutron capture spectroscopy model; and identifying the lithostratigraphic layers within the subterranean formation by applying the model to well logs of non-target wells.

Reservoir characterization using rock geochemistry for lithostratigraphic interpretation of a subterranean formation

A petrophysically regularized time domain nuclear magnetic resonance (NMR) inversion includes using an NMR tool to acquire NMR data and inverting the acquired NMR data in a time domain using petrophysical constraints. The inverted NMR data is analyzed. The petrophysical constraints may be identified by: determining a number of porobodons to seek, defining a plurality of zones in which only a subset of porobodon sets is present, and stacking all NMR echoes in each zone satisfying discriminators. The number of porobodons to seek may be based on knowledge of core samples, logs, and NMR sensitivity. The discriminator logs may be logs sensitive to porosity partitioning. A computing system having a processor, a memory, and a program stored in memory may be configured to perform the method. The system may be conveyed downhole on a wireline, a while-drilling drill string, a coiled tubing, a slickline, or a wired drill pipe.

Petrophysically regularized time domain NMR inversion

A roadmap for a field development strategy for optimal recovery is provided in a high quality 3D geological model. This geological model combines geological attributes, pore and rock properties for an optimum 3D representation of the reservoir thousands of feet beneath the surface. The model is based on the pertinent geological facies, derived from well core description and detailed studies of rock, as well as fluid and pore properties (Full Pore System) obtained from laboratory analyses of core material and well log data. These data differentiate various important pore throat and pore body regions and relationships, i.e., macroporosity and microporosity. Understanding hydrocarbon volumes in the various pore type groups and then establishing proper recovery techniques through focused laboratory studies yields a field development strategy that can significantly increase hydrocarbon recovery from a reservoir.

Three-dimensional multi-modal core and geological modeling for optimal field development

A method of measuring a formation parameter in the process of drilling a well penetrating the rock formation is disclosed. A section of the well is provided with a drill string comprising a drilling bit at its distal end; a first fluid is circulated through the drilling bit and invades the rock formation; a formation evaluation tool mounted onto the drill string is used to measure the formation parameter; the formation parameter is used to select the time at which a second fluid is circulated through the drilling bit; such that the second fluid alters the response of the rock formation to the formation evaluation tool; the second fluid is circulated through the drilling bit to start invading the formation; and the formation evaluation tool is used to repeat the measure of the formation parameter while circulating the second fluid.

Method of determining a formation parameter

Asphaltene content and its spatial distribution in a reservoir containing crude oil is an important factor in determining the potential for formation damage and pipeline impairment, as well as planning for processing and refining of the oil. Exemplary uses include: reservoir modeling, development and depletion planning, pressure maintenance, and surface facilities management. A convenient method has been developed which uses two-dimensional NMR techniques during a temperature and/or pressure cycle to quantify the asphaltene content of the crude oil without the need for extracting the oil from the reservoir rock. The technique can be applied to core, down-hole logs, or, a combination of both.

Asphaltene evaluation based on NMR measurements and temperature / pressure cycling

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Dhahran, Saudi Arabia

Edward Alan Clerke