Summary
This paper describes a single-well pilot in which light-oil diluent was injected through tubing to lower in-situ oil viscosity and increase production from a low-gravity oil well. The pilot well is located on the Heritage platform in the Santa Ynez Unit and produces from the Monterey formation. The pilot validated laboratory data suggesting that large production-rate increases could result from high-rate diluent injection.
Introduction
The Monterey formation is a complex reservoir with intense structuring, fracturing, and highly variable rock properties. It is a dual-porosity system, with low-permeability matrix rock and extensive fracturing. The fractures provide the flow path to the wells and are well-connected to a very large aquifer. The fluid system is equally complex. The original oil column was 2,000 ft thick, and the oil gravity varied from 5 to 19°API. Gravity/depth relationships vary within the field area.
Heavy oil, as defined in this paper, is oil with dead-oil gravities of approximately 11°API or less. Fig. 1 is a geothermal temperature-gradient curve for offshore California. Fig. 2 is an estimation of live-oil viscosities for Monterey crude as a function of temperature and dead-oil gravity. Recovering the heavier oil at economic rates without producing large volumes of water is a challenge owing to a strong aquifer, highly permeable fractures, and a poor oil/water viscosity ratio. Achieving the large drawdown required to produce heavy oil at the high rates needed for economic operations offshore can result in the oil being bypassed by water flowing through the fractures. Even if bypassing can be avoided, the flow rate of heavy oil to the wellbore can be low. Furthermore, cooling of the heavy oil as it reaches the seafloor results in additional producing problems. As seen in Fig. 2, a 10°API oil has an in-situ viscosity of 100 cp at 200°F. As the heavy oil flows to the surface and cools, viscosity can rise above 10,000 cp and cause severe lifting problems. Deep, long throw wells (6,000 to 10,000 ft subsea), an offshore operating environment, a fracture zone with an active aquifer, and low heavy-oil prices rule out most methods of heavy-oil recovery. The challenge is to find a low-cost method to lower the oil viscosity in both the near-well region and the tubing. This paper documents a simple and inexpensive way to lower viscosity by an order of magnitude or more through cyclic injection of light oil.
Theory
Darcy's Law for radial, steady-state flow describes fluid flow in porous media. This simple equation gives guidance and insight to solve many oil-production problems:Equation 1
This pilot focused on reducing viscosity (µo) as a method to increase production rate (q). While the other components are also important, they were less critical for the following reasons:Fracture permeability in the major producing intervals of the Monterey formation in the Santa Barbara Channel is excellent. Wells have produced at rates in excess of 9,000 STB/D from as little as 40 ft true vertical depth (TVD) of the perforated interval. Average permeabilities are in the multidarcy range.High drawdowns may be harmful in the long run because of an unfavorable oil/water viscosity ratio. High drawdowns can result in water coning and fingering through the fractures, leaving bypassed oil in the formation. In addition, alternative lifting methods to increase drawdown can be costly owing to long throws and deep completions in the offshore environment.
Reducing in-situ oil viscosity can improve the oil/water viscosity ratio, reduce water coning and fingering, reduce water cut, reduce lifting problems, and increase production rates and oil recovery from fractured heavy-oil reservoirs.
HE-26 Pilot
Background.
The Heritage platform began producing from the Pescado field in the Santa Ynez Unit in December 1993. Wells produce 10 to 17°API oil from the Monterey and 34°API oil from sandstone formations. The Monterey formation consists of thin beds of porcelanite, chert, calcite, dolomite, and shale. The beds are highly fractured and well-connected both areally and vertically by an extensive fracture network. The fractures provide the primary flow paths in the reservoir and result in well rates as high as 10,000 STB/D. Formation pressure is supported by re-injection of produced gas and by a large, well-connected aquifer. The original oil column was approximately 2,000 ft thick and contained undersaturated oil with gravities grading from 19°API at the crest of the structure to 5°API at the original oil/water contact. Wells either flow naturally or are produced by high-volume gas lift. The sandstone formations lie below the Monterey and contain light oil with an associated gas cap. Sandstone wells flow naturally without the need for artificial lift.
HE-26 History.
The HE-26 well was drilled and completed in July 1997 in the Monterey formation, with perforations at 6,956 to 6,997 and 7,416 to 7,437 ft subsea. The well was stimulated with a combination of xylene, HCL, and mud acid, using foam and ball sealers for diversion. After stimulation, the well produced approximately 100 STB/D of 10.2°API oil and water. These perforations were isolated with a through-tubing bridge plug, and the well was reworked higher to 6,751 to 6,801 ft subsea. The new perforations were stimulated in a similar fashion. Oil gravity increased slightly, but production rates were unchanged. The interval was isolated with another through-tubing bridge. A final interval was perforated at 6,667 to 6,702 ft subsea. Oil gravity was slightly higher (11.4°API), but oil production rates once again did not change.
Phase-Field Simulation of Imbibition for the Matrix-Fracture of Tight Oil Reservoirs Considering Temperature Change