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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.

This paper shows that the water-alternating-gas (WAG) process may improve sweep efficiency and gas-condensate recovery compared with continuous cycling in highly stratified reservoirs. The study used extensive numerical simulation to investigate the sensitivity of the process to several variables, including reservoir layering, permeability, relative permeability, capillary pressure, and trapped gas. The process mechanics were confirmed by laboratory displacements in layered core.

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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.

An unconventional method to improve sweep efficiency in highly stratified or naturally fractured gas condensate reservoirs has been explored through simulation studies.The alternating water and gas injection process (WAG) has not been heretofore seriously considered in gas cycling projects for fear of losing ultimate production. For the base case study presented here, however, WAG is shown to improve sweep efficiency and ultimate recovery by 86% at one pore volume injection over that of dry gas injection alone into a prototype gas condensate reservoir containing a single, high permeability thief zone. The increase in sweep efficiency occurs primarily because the high viscosity water tends to block the thief zone, thus forcing following inj ection gas to invade the reservoir matrix.The principal factors governing the process are the contrast between thief zone and matrix permeabilities, the viscosities of inj ected gas and water, and the residual gas saturation to water. Varying the relative permeability curves and water/gas slug sizes and ratios had smaller effects on the results. Since only relatively small amounts of water are required to obtain large increases in recovery, expected detrimental effects from gas trapping and premature abandonment are limited.An additional economic benefit arises because the water occupies space which must otherwise be occupied by make-up gas.