Heavy Oil Recovery By Conventional And Mining Methods
Authors: DeMirjian H.A. 
Published: December 2007

Introduction

Oil production rate and ultimate primary recovery from a heavy or viscous oil reservoir usually is limited to a very small fraction of the original oil in place. Typically, normal production rate is in the range of up to 10 B/D and expected ultimate cumulative production is up to 10 percent of in-place values. All heavy oil reserves are not alike. The physical properties of the rock, the liquid hydrocarbons, and depths of the deposits are so different that each reservoir poses a unique enhanced oil-recovery problem. In some reservoirs thermal recovery by internal heat generation or external heat injection has been exploited successfully. In other reservoirs, mining the oil-bearing formation for oil recovery by surface processing has been practiced. This paper will present an overview of the heavy oil-recovery state of the art and discuss the critical factors leading to the decision for selection of a conventional hydrocarbon recovery or mining and extraction processes.

POTENTIAL OF HEAVY OIL POTENTIAL OF HEAVY OIL In various localities through the world, there are large deposits of very viscous hydrocarbons that are not easily recoverable by conventional methods. A considerable volume is found in the United States and Canada. The best known Canadian deposit is in the Athabasca district of Alberta Province. In the United States, Oklahoma has over 150 tar-sand occurrences with a depth of less than 500 ft. California, Kentucky, Utah, eastern Kansas, western Missouri, and Texas also have large, shallow accumulations broadly classified as tar sands. The general geologic and reservoir features of the U.S. heavy oil deposits closely resemble those currently being exploited in California's San Joaquin Valley and coastal areas. The exception is that these California crudes have a slightly higher gravity and lower viscosity than most other U.S. tar-sand deposits.

It may be worthwhile to classify broadly what has been referred to as heavy hydrocarbons. The U.S. shale-oil deposit, contain what is commonly known as kerogen, which is a solid under ambient conditions. The tar sands of Canada and the U.S. contain a liquid hydrocarbon known as bitumen with an API gravity in the range of 4 to 8 degrees. Under normal reservoir conditions, bitumen is not movable in host rocks. The heavy oil fields scattered throughout California contain an asphaltic liquid hydrocarbon ranging in gravity between 8 to 20 deg. API. In contrast to the previous types, these heavy oils can be produced by previous types, these heavy oils can be produced by conventional methods. The major effort in enhanced oil recovery by thermal methods throughout the U.S. has been with these heavy oils similar to those commonly found in California. Crude oils that can be produced by conventional thermal-recovery methods do not require upgrading prior to refining. Thus, they have a great advantage over solid fossil fuels such as kerogen, bitumen, and coal in conversion to conventional fuels or other products.

THEORY AND TECHNOLOGY

The flow of fluids through porous media can be described in its simplest form, by the Darcy equation developed over 100 years ago and used extensively throughout the petroleum industry. This equation relates the properties of the rock, the flowing fluid, and the available energy to expel or move a fluid underground from one area to another. For all practical purposes, we can assume the heavy oils to practical purposes, we can assume the heavy oils to behave like incompressible fluids. The derivation of the flow equation is as follows:

(1)

where Vx = apparent fluid velocity in the x direction k = a property of the rock known as permeability mu = viscosity of the flowing fluid dp/dx = pressure gradient in the direction of flow

The Vx term can be replaced by Q/A, where Q is the rate of flow and A is the cross-sectional area available for flow.