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.

Pilot in-situ combustion oil recovery operations began in the South Belridge Field in 1963, and commercial operations began on a 164-acre area in 1964. This operation ended in 1986 when an air compressor failed. South Belridge oil in place of a third of billion barrels of oil with an estimated 8 percent recovery inspired interest in thermal oil recovery in 1947. This study presents results of 22 years of commercial in-situ combustion at South Belridge. Although continuous steam injection is the most important thermal oil recovery operation in South Belridge, in-situ combustion offers opportunity for extending thermal operations in other fields far beyond bounds appropriate for steam injection. Results at South Belridge for both commercial steam injection and in-situ combustion have been published. Steam injection is among the best in California, and in-situ combustion is considered average for California conditions. At South Belridge, the surface energy requirement per barrel of oil produced by in-situ combustion was about one fifth that required for steam drive. The pounds of flue gas generated per barrel of oil recovery from in-situ combustion was about half that required for steam drive. Emulsions were produced by in-situ combustion, but posed no special problems. Well failures for in-situ combustion were similar to those for steam drive once old (pre-1964) completions were replaced. The ratio of cum. inj. air to cum. prod. oil was 3.7 MCF/BBL, about a third of the design ratio. In-situ combustion offers an efficient extension of thermal enhanced oil recovery to deep, high-pressure, low-oil-reactivity formations.

SPE Members Abstract A field test of wet in-situ oxygen combustion has been carried out in the Esperson Dome field in southeast Texas. The objectives of the pilot test were to evaluate the potential of oxygen combustion technology, to assess its advantages over air fireflooding, and to gain experience in the safe handling and downhole injection of high purity oxygen in an oil field environment. The Miocene sandstone chosen for the pilot is relatively deep (2700 feet), thin (20 feet), and had been substantially watered-out by a strong natural water drive. At the beginning of the combustion pilot an estimated 850 bbl/acre-ft (36% saturation) of 90 cp (21 degrees pilot an estimated 850 bbl/acre-ft (36% saturation) of 90 cp (21 degrees API) oil remained in place. The natural water drive dominated the combustion process and assisted in displacing the oil. At project termination, 200 MMscf of oxygen and 55 MMscf of nitrogen had been injected, 90,000 barrels of oil recovered, four existing older wells failed, four new wells drilled, and three wells burned out. Determination of incremental oil is uncertain due to these operational changes. The objectives of the project were met, and improvements in the project design and operation are expected to lead to an economic project design and operation are expected to lead to an economic process for further applications. process for further applications Introduction In-situ combustion has been used since the early 1940's to thermally stimulate oil reservoirs. Traditionally, compressed air has been injected into the formation at a flux great enough to drive a combustion front across the reservoir. Gates and Ramey reported results of the first successful field test of air fireflooding in South Belridge in the mid 1950's. A review, of all reported field tests is given by Chu. The oxygen-driven in-situ combustion process is considered to be more efficient than air, due to the absence of nitrogen. Advantages include:a lower gas flux mitigates sanding, erosion, and pumping problems at the production well and allows a higher effective pumping problems at the production well and allows a higher effective permeability to oil in the reservoir;a higher CO2 concentration permeability to oil in the reservoir;a higher CO2 concentration in the flue gas allows more CO2 dissolution in the oil thereby reducing its viscosity; anda higher net oxygen injection rate will result in an accelerated oil recovery and possibly permit a wider well spacing. The process can be applied to reservoirs where combustion would not be sustained with air. In the wet combustion mode, higher water injection rates are possible, thereby improving the sweep efficiency. With recent developments in cryogenic technology, oxygen prices are competitive with air compression costs and may be lower at injection pressures higher than 1000 psi. This emerging technology is being applied to recover heavy and medium gravity oils and shows promise. For example, the process has been applied to heavy oils in a secondary mode and to medium and light oils in a tertiary mode. To test the viability of this technology, Mobil designed and implemented a pilot test in the Esperson Dome field. This inverted seven-spot pilot was designed in 1983 based on laboratory and simulation results. The injector was a new well drilled low in the structure, with existing older wells as producers. The location of the injection well took advantage of the water influx to constitute a wet in-situ oxygen fireflood. This paper describes the design and performance of the pilot test. The laboratory efforts associated with the pilot design are briefly presented. presented. THE WET IN-SITU OXYGEN COMBUSTION PROCESS The oxygen combustion process with its associated zones and temperatures is shown in Figure 1. The process involves injecting oxygen or oxygen enriched air into an oil bearing formation through an injector well. After ignition occurs, continued oxidant injection causes the combustion front to move through the formation away from the injection well. The heat generated by combustion lowers the viscosity of the oil in place, thus enhances its mobility. Combustion or flue gases are absorbed by the reservoir oil or produced with the other fluids. Heat generated at the combustion front, where peak temperatures may range from 400 to 2000 degrees F, will vaporize formation water to create a steam zone. Most of the oil ahead of the combustion front is displaced by this advancing steam zone. The oil left behind, which is often the heavy hydrocarbons of the crude, is used as the fuel to sustain the combustion. P. 157

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 essential reservoir fluid property for reservoir engineering, fluid transport design, and reservoir simulation is the fluid density (compressibility factor). The oil density as a function of pressure is normally available from standard laboratory measurements. But in cases of enhanced oil recovery by gas injection or miscible flooding, or in multiphase transport, the dramatic changes in fluid density as a function of concentration and pressure are commonly not measured, and standard correlations are generally inaccurate. Two-parameter equations of state, e.g., Peng-Robinson, and extended corresponding states also predict densities inaccurately for complex reservoir fluids. We demonstrate computational improvements and the use of the critical volume as an adjustable parameter to the extended corresponding states principle (ECSP) to improve predictions of petroleum reservoir fluid densities. This new method provides accurate and computationally reliable predictions for complex petroleum fluids. We illustrate with five example systems.