EOR Development Screening of a Heterogeneous Heavy-Oil Field

Abstract

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 129157, ’EOR Development Screening of a Heterogeneous Heavy Oil Field- Challenges and Solutions,’ by J.P. Strauss, SPE, D.M. Alexander, SPE, N. Al-Azri, M. Al-Habsi, SPE, T. Al-Musallami, M. Koning, F. Eriavbe, Mukman Mukman, and, R. Al-Jarwani, Petroleum Development Oman, and A.J. Landman, SPE, Shell Technology Oman, originally prepared for the 2010 SPE EOR Conference on Oil and Gas West Asia, Muscat, Oman, 11-13 April. The paper has not been peer reviewed. The full-length paper details an enhanced-oil-recovery (EOR) development-concept screening from a subsurface perspective. The field is a medium-sized heavy-oil field with complex geology and is in South Oman. The two primary concepts considered are steamflood and polymer flood, each of which presents its own challenges. Common to both concepts is the difficulty in obtaining adequate conformance in a field that is characterized by high and highly variable permeabilities in a channelized environment and that includes lateral extensive shales that break the system into vertically distinct sand units. Introduction The field has been under primary production by use of progressing-cavity pumps (PCPs) since January 1989, with 35 vertical wells and one horizontal well drilled within the field oil/water contact. The oil is medium heavy (18°API), has a low gas/oil ratio (less than 0.2 m3/m3), and is relatively viscous (400 to 1,000 cp), implying a very adverse-mobility-ratio for displacement of oil by water. In spite of this, many wells show a slow development of water cut, though they ultimately pro-duce at high water cuts. Observations of pressure vs. depth show evidence of local differential depletion of individual sand units and, coupled with the slow water-cut development, support the concept of laterally extensive shales. Pressures in the deepest sand unit show an initial decline followed by recent recharge in spite of increased off-take. This is interpreted as representative of the changes in the regional aquifer pressures that are being driven by much larger off-take and water-disposal volumes at neighboring fields. Historical production has achieved a low recovery, given the relatively low rates achievable with vertical wells under cold production and the high water cuts once water breakthrough has occurred. Thermal recovery initially was identified as the only mature EOR approach that conceivably could achieve a reasonable recovery in such a system, and, as a consequence, the operator has embarked on a single-pattern steam trial that has been operating since 2008. Recent data-gathering and -analysis efforts including downhole sampling with a wireline formation-testing tool have revised initial estimates of oil viscosity downward, allowing a wider range of development concepts to be considered.