Determining Swept-Zone Residual Oil Saturation in a Slightly Consolidated Gulf Coast Sandstone Reservoir

Abstract

This paper reviews quantitative determinations of swept-zone residual oil saturation in the slightly consolidated sandstones of the Tertiary System of the Gulf Coast. Different residual oil saturation measuring techniques were evaluated. Results obtained from all techniques showed good agreement of residual oil saturation values among the different techniques. Introduction The volume of oil remaining in major reservoirs after water floodout is potentially attractive for tertiary projects. However, an accurate determination of residual projects. However, an accurate determination of residual oil saturation (Sor) is essential for every reservoir, not only to evaluate the potential for tertiary recovery, but also to understand a waterflooded reservoir's current performance. performance. Evaluation of primary and secondary production mechanisms and ultimately, the prediction of potential tertiary reserves, hinge on the Sor-porosity product, (Sor phi). Yet, the determination of Sor (assuming porosity can be determined accurately) has not been easy porosity can be determined accurately) has not been easy to achieve in the soft formations of south Louisiana. Mechanical problems with tools and techniques together have made this important parameter difficult to obtain. Thus, evaluation of the most promising of the existing Sor measuring techniques was necessary to provide guidance for future determinations. The reservoir chosen for this vanguard effort was the 7,800-ft (2400-m) "Q2" sand of Reservoir A in the Main Pass Block 69 Field, offshore Plaquemines Parish, LA (Fig. 1). The "Q2" Sand is an upper Miocene, fault-controlled, deltaic formation and was produced first in the Reservoir A fault block in 1956. Fig. 2 is a log section showing the Sor project well, S.L. 1357 No. 46, and a nearby well, S.L. 1357 No. 16. Stringer drainage and uneven water encroachment are common in this multilayered reservoir (Figs. 2 and 3). The original reservoir pressure was 3,700 psi (25.5 MPa) which had dropped to about 3,000 psi (20.7 MPa) before water injection began. The reservoir pressure is now stabilized at about 2,500 psi (17.2 MPa). Initially, the crude oil was saturated and the reservoir had an original gas cap (Fig. 4). At the onset of this test, the best estimate for Sor in the good quality rock in the "Q2" sand of Reservoir A was about 20 to 30%; however, a good chance of significant error in this estimate existed. Therefore, Shell wanted to determine as accurately as possible the swept-zone residual oil saturation for this major reservoir. Well S.L. 1357 No. 46, a field development well, was chosen for this project. Because it was recognized that this would be a difficult project, many man-months were spent in, planning. Every effort was made to anticipate technical problems and many of the staff at Shell Development Co.'s Bellaire Research Center worked to find solutions. Wellsite work was supervised closely by experienced personnel from the Coastal Div. and the research center. This supervision included continuous calculating and monitoring. This ensured that all necessary data of good quality were gathered. Presentation of Operations Presentation of Operations Fig. 5 compares the schematic hole profile and penetration rate plot for this well with the sand section depicted penetration rate plot for this well with the sand section depicted by a dual induction log. JPT P. 513