The presentation here is brief and does not include the intermediate steps of the mathematical derivation of the key equations. The details of these mathematical derivations are available in Willhite.[1] The displacement of oil by water from a porous and permeable rock is an unsteady-state process because the saturations change with time and distance from the injection point (see schematic diagram of Figure 1)[2]. These saturation changes cause the relative permeability values and pressures to change as a function of time at each position in the rock. Figure 1 illustrates the various stages of an oil/water displacement process in a homogeneous linear system.

At the pore level (i.e., where the water and oil phases interact immiscibly when moving from one set of pores to the next), wettability and pore geometry are the two key considerations. The interplay between wettability and pore geometry in a reservoir rock is what is represented by the laboratory-determined capillary pressure curves and water/oil relative permeability curves that engineers use when making original oil in place (OOIP) and fluid-flow calculations. This article discusses these basic concepts and their implications for initial water- and oil-saturation distribution, relative permeability, and how initial gas saturation will affect water/oil flow behavior. Figure 1[1] is a schematic diagram of the water/oil displacement process. Wettability is defined in terms of the interaction of two immiscible phases, such as oil and water, and a solid surface, such as that of the pores of a reservoir rock.

The Ekofisk oil field[1][2][3] is in the North Sea, south of Norway, with an estimated 6.4 billion bbl stock tank original oil in place (STOOIP). It is a large, carbonate reservoir that has two zones, Ekofisk and Tor, that are high-porosity, fractured chalks with matrix permeabilities of approximately 1 md and effective permeabilities that range from 1 to 50 md. Discovered in 1969, the Ekofisk field was found at very high pressure [7,120 psia at 10,400 ft true vertical depth subsea (TVDSS)] but with an initial bubblepoint pressure that was 1,600 psi below initial reservoir pressure. Ekofisk's oil is 38 API, has a viscosity of approximately 0.25 cp, and has a solution gas/oil ratio (GOR) of more than 1,500 scf/STB. Primary production began in June 1971 and peaked in 1976 at 350,000 barrels of oil per day (BOPD) from 30 production wells (with 8 gas reinjection wells).

The Long Beach Unit (LBU) area of the Wilmington oil field (southern California, US) is mainly under the Long Beach harbor and contains more than 3 billion bbl of original oil in place (OOIP).[1][2][3] This oil field is a large anticline that is crosscut by several faults with displacements of 50 to 450 ft. It consists of seven zones between 2,500 and 7,000 ft true vertical depth subsea (TVDSS), the upper six of which are turbidite deposits of unconsolidated to poorly consolidated sandstone (1 to 1,000 md and 20 to 30% BV porosity) interbedded with shales. The gross thickness of 3,300 ft contains 900 ft of sandstone. From its discovery in 1936 to the 1950s, most of the onshore portion of this oil field (the non-LBU area of the Wilmington oil field) was produced using the pressure-depletion oil-recovery mechanism.

Waterdrive (or water drive) petroleum reservoirs are characteristically bounded by and in communication with aquifers. As pressure decreases during pressure depletion, the compressed waters within the aquifers expand and overflow into the petroleum reservoir. The invading water helps drive the oil to the producing wells, leading to improved oil recoveries. Like gas reinjection and gas cap expansion, water influx also acts to mitigate the pressure decline. The degree to which water influx improves oil recovery depends on the size of the adjoining aquifer, the degree of communication between the aquifer and petroleum reservoir, and ultimately the amount of water that encroaches into the reservoir.

Oil reservoirs that do not initially contain free gas but develop free gas on pressure depletion are classified as solution gas drives. The solution gas drive mechanism applies once the pressure falls below the bubblepoint. Both black- and volatile-oil reservoirs are amenable to solution gas drive. Other producing mechanisms may, and often do, augment the solution gas drive. Solution gas drive reservoir performance is used as a benchmark to compare other producing mechanisms.

The following 62 pages are in this category, out of 62 total.

Although conformance-improvement gel treatments have existed for a number of decades, their widespread use has only begun to emerge. Early oilfield gels tended to be stable and function well during testing and evaluation in the laboratory, but failed to be stable and to function downhole as intended because they lacked robust chemistries. Also, because of a lack of modern technology, many reservoir and flooding conformance problems were not understood, correctly depicted, or properly diagnosed. In addition, numerous individuals and organizations tended to make excessive claims about what early oilfield gel technologies could and would do. The success rate of these gel treatments was low and conducting such treatments was considered high risk. As a result, conformance-improvement gel technologies developed a somewhat bad reputation in the industry. Only recently has this reputation begun to improve. The information presented in this chapter can help petroleum engineers evaluate oilfield conformance gels and their field application on the basis of well-founded-scientific, sound-engineering, and field-performance merits.

Gels are a fluid-based system to which some solid-like structural properties have been imparted. In other words, gels are a fluid-based system within which the base fluid has acquired at least some 3D solid-like structural properties. These structural properties are often elastic in nature. All of the conformance improvement gels discussed are aqueous-based materials. The term "gel" as used in this page (unless specifically noted otherwise) refers to classical, continuous, bulk, and "relatively strong" gel material and does not refer to discontinuous, dispersed, "relatively weak," microgel particles in an aqueous solution. Gels discussed in this page, when formed in a beaker for example, constitute a single and continuous gel mass throughout its entire volume within the beaker.

When an aqueous gel is contacted under appropriate conditions, chemical breakers can degrade the gel back to a low-viscosity and watery solution. This article briefly describes the use of gel breakers and the types of gel breakers used in the industry. There are several reasons why a chemical breaker cannot be used to successfully and fully degrade a gel that has been placed deeply in either a matrix-rock or a fractured reservoir. First, successfully delivering the chemically reactive gel-breaker solution deeply in an oil reservoir is a daunting task. Second, and more fundamentally problematic, even if a chemical breaker solution could be 100% effective in the reservoir during its entire gel-breaking life, once injected into the reservoir, the gel-breaker solution would tend to wormhole through the emplaced gel.