Gravity drainage is normally characterized as a slow but efficient process, leading to a low remaining oil saturation. If the reservoir has a large oil column and a high vertical permeability, then efficient recovery may be achieved through the gravity drainage process that accompanies a stable gas cap expansion. An extensive experimental program was conducted to characterize the flow properties of the gravity drainage process where oil is displaced by gas in the presence of an initial water saturation. The experiments described here were designed to give endpoint saturations, oil relative permeabilities, and gas relative permeabilities for the gas-displacing-oil gravity drainage situation. No single test provides all of these parameters required for performance prediction. Long core gravity drainage tests, as well as porous plate and centrifuge tests, were performed at simulated reservoir conditions. The long core drainage tests were conducted in a vertical coreflood apparatus in which in-situ oil and water distributions were monitored regularly using both x-ray and microwave scanning systems. The experimental results support the following conclusions with regard to high permeability, unconsolidated sands: • Residual oil saturation to the gravity drainage process (S org) is low, 3-10% and is somewhat insensitive to rock properties. This level of saturation is achieved through film drainage and may require considerable time and suitable conditions (oil column height and fluid density differences). • S org is not sensitive to fluid properties such as viscosity, interfacial tensions, and spreading coefficient for the limited systems studied. • S org does not depend on initial water saturation within a reasonable range. • k ro and k rg depend on rock properties. • Conventional gas flood tests give higher S org (average 30%), even at high volume (1000 PV) and/or low rate gas injection, and do not represent the gravity drainage process. These laboratory findings were validated by a subsequent coring operation, using a low invasion water-based mud, in the secondary gas cap of the Ubit field, offshore Nigeria, that had been in production for twenty-five years. The residual oil saturations to gravity drainage found in the secondary gas cap agreed well with laboratory results. However, the observed S org was not achieved in the simulation of the field history when detailed geological description and the lab measured k ro was used. Adjustment of k ro by an order of magnitude near the S org was necessary to match the S org distribution observed in the secondary gas cap. It was found that the low k ro close to S org was an artifact due to capillary end effects, not fully accounted for in initial modeling. Subsequent lab tests were designed to generate appropriate data for reservoir management. Adjustment of k ro was justified when data were reanalyzed, taking P c into consideration, and bringing laboratory measurements, field observations, and reservoir simulation into complete agreement.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractUbit field is an example of a successful application of integrated reservoir management to an old field, which has resulted in a total change in the development strategy, an increase in recoverable reserves by a half billion barrels and a production uplift of 110 MBD. The key was an improved understanding of the reservoir hydraulics. Unlocking the genesis of elements that defined the fluid flow units identified their connectivity and distribution as related to their depositional facies, led to rejuvenating this field so completely. New data and techniques in 3-D seismic, core interpretation, computer mapping, 3-D visualization, and advanced reservoir simulation prediction capabilities were brought together to optimize recovery and production. Through the integration of the new reservoir model, horizontal drilling, and surface facilities, this old field is now producing an all-time high of 140 MBD, with ultimate recovery expected to exceed 1 billion barrels. The techniques and methodologies developed at Ubit are being leveraged in other assets.Ubit has a STOIIP of 2.1 billion. The reservoir is cut by 3500 feet of dipping, unconsolidated sands and shales. Production is from a thin oil column, with an associated thick gas cap. Gravity-stable gas expansion is the primary recovery mechanism. For 25 years, Ubit averaged only 30 MBD with a high gas-oil ratio.Gas breakthrough in conventional directionally-drilled production wells has been problematic. Previous reservoir interpretations described the chaotic nature and poor quality reservoir properties in the eastern two-thirds of the field. Poor historical production performance seemed to confirm these observations.A new horizontally-layered, hydraulic-focused geologic model combined with advanced reservoir simulation techniques yielded a substantially improved interpretation. The reservoir model is the primary focus of this paper. Predicted performance has guided the management of the re-development of Ubit. New technology applications and conventional techniques were brought together in the reservoir model design to capture the geologic elements controlling flow, and the dynamic processes controlling recovery.This paper describes some of the significant reservoir engineering, geoscience, infrastructure challenges, and the technical resolutions during the development and management of this complex reservoir system. Key reservoir management strategies were applied to maximize performance and ultimate recoveries. They include: 1) implementing horizontal well drilling, 2) full-field full-life reservoir simulation results defining well placement / timing, 3) balancing a non-uniform gas cap, 4) maintaining stable gas cap movement and pressure throughout, 5) establishing a field plateau rate and 6) minimizing free-gas production.

SPE Members Abstract Two thermally enhanced oil recovery methods, cyclic steaming and steamflooding, have been investigated by means of numerical modeling for a massive, dipping, Midway Sunset Field reservoir. Comparative economics have been evaluated for the development alternatives. The results of the investigation indicate that ultimate recovery efficiency is not sensitive to the method of steam delivery to the reservoir. Cyclic steaming methods recovered the same percentage of original oil in place as did steamflooding. The cyclic operations required several times longer than steamflooding to reach the same ultimate recovery efficiency. On a steam utilization efficiency basis (oil to steam ratio), cyclic steaming with small steam slug volumes proved to be the most efficient recovery method. As the rate of steam injection increased, the steam utilization efficiency decreased, regardless of the manner in which steam was delivered to the reservoir. Despite having the poorest steam utilization efficiency, steamflooding provided far superior economics as compared to conventional low or moderate slug volume cyclic steaming. This is directly attributable to steamflooding having the fastest rate of increase in average reservoir temperature and therefore the greatest rate of net recovery as compared to the alternatives investigated. Steamflooding exhibited a much quicker payout of development capital and a greater present value return per dollar invested. Introduction While thermally enhanced oil recovery methods are an attractive method of extracting heavy oil, due to the large development capital costs and the significant expense in steam generation, it is important to look critically at development alternatives and to choose the method that is most attractive to the investor. A cyclic steaming project is operated significantly different from that of a steamflood. Consequently, it requires a different facilities configuration in order to allow effective optimization during its operation. It is costly to install a facilities design tailored to one method, and then to retrofit for an alternative operating strategy. It is therefore essential to choose the more attractive manner in which steam is to be delivered to the reservoir and to install and operate the project in this manner. Thermal EOR textbooks indicate that, in general, greater recovery efficiencies are possible with steamflooding than with cyclic steaming. It is generally written that while steamflooding can be expected to recover 50–60% of the original oil in place, cyclic steaming typically recovers only 10–25%. Cyclic steaming is viewed as a stimulation method with rapid response while there is a lag in the production response associated with steamflooding. The Potter Sand in the Midway Sunset Field has been developed and operated with cyclic steaming as well as a steamflood by various operators. Both methods are viewed by their respective operators as technical and economic successes. P. 429^

SPE Members Abstract Thermal reservoir simulation was utilized to understand, make development recommendations, and project the performance of the Monarch C steamflood in a portion of Mobil's South Midway Sunset field. The Monarch, a thick sequence of complex turbidite deposition, is characterized by extreme geological heterogeneity (lithofacies-controlled permeability and saturation variation, and mudstone barrier layers). Steamflood performance in the Monarch is related directly to the reservoir quality, and the path of steam flow is significantly influenced by the numerous laterally extensive mudstone barriers. The fine grain clay-bearing sediments were deposited on the anticline, distal from the source, whereas the coarser grain sediments, with little clay, were deposited on the more proximal syncline and steep dip areas. Consequently, steamflood performance improves relative to the crest since reservoir quality improves (including oil saturation), clay content decreases, and structure (dip) becomes more pronounced. The simulation models were constructed to capture the heterogeneity. Two models were constructed, a single pattern model for a pattern with good performance, and a multi-pattern strip model that linked patterns of good performance with poorly performing patterns on the crest of the structure. Simulation results indicated the initial completion strategy, that ignored the mudstone barriers, often resulted in misalignment between injector and producer completions that severely limited performance. A complete overhaul of the well completions was required to improve the steamflood. Subsequent to the simulation work, the steamflood was re-engineered, based on intensive pattern-by-pattern and well-by-well reviews, to include producer recompletions and limited entry steam injectors. Steamflood performance improved following the redesign. Introduction Mobil's MOCO 35 Fee Property in the South Midway Sunset field is located in Kern County, California. The Monarch, composed of four retrograding turbidite reservoir complexes (A, B1, B2, and C), offers an unusually complex geological environment for steamflood development. These sands were produced under primary and cyclic steam until an aggressive steamflood development plan was initiated in the mid-1980's for three of the reservoir complexes. A four-pattern pilot was started in 1986-87 (five-acre nine spots) and followed by further expansion in 1989-90. Steamflooding often includes a significant gravity drainage contribution, and therefore performance can be enhanced in reservoirs that have significant structure. In general structural terms, the Monarch sands consist of an anticline (present during deposition) that gently slopes into a syncline. Past the syncline, the sands have been greatly uplifted through Post-depositional folding resulting in a highly dipped structure ("steep dip"). The 12-pattern 1989 Expansion lies primarily on the top of the anticline, with the southern 3 patterns in the synclinal region. Figure 1 shows MOCO Section 34 and 35, the structural configuration, and the location of the pilot and the 1989 Expansion area. Subsequent development has moved west of the anticline, but has concentrated on the synclinal region and the highly productive steep dip area to the south and southwest. Figure 2 shows a schematic strike cross section for the three main sands of the Monarch: B1, B2, and C. Figure 3 shows a dip cross section for the same sands. P. 279

Mobil has completed the design phase of a steamflood project in a thick, moderately dipping, unconsolidated heavy oil reservoir. The design takes advantage of the gravity drainage recovery mechanism in the thick reservoir, allowing vertical steam zone expansion with minimal steam breakthrough. This steamflood project is economic in the late 1980's period of low oil prices. The design was completed with an interdisciplinary teamwork approach using concurrent studies for expediency. BACKGROUND During 1987, Mobil undertook a scoping study of its U.S. heavy oil producing properties, looking for areas of high potential for the 1990's. Several successful cyclic steam operations were identified as having potential that could be exploited using modern steamflood technology. The scoping study showed that the subject project had a reserve potential on the order of tens of millions of barrels of oil. The study documented here was undertaken to better determine the potential of this project.