Produced-Water-Volume Estimates and Management Practices

Abstract

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 125999, ’Produced Water Volume Estimates and Management Practices,’ by J.A. Veil, SPE, and C.E. Clark, Argonne National Laboratory, originally prepared for the 2010 SPE International Conference on Health, Safety, and Environment in Oil and Gas Exploration and Production, Rio de Janeiro, 12-14 April. The paper has not been peer reviewed. Produced water is the largest byproduct associated with oil-and-gas production. Within the USA, nearly one million oil or gas wells are producing hydrocarbons with various volumes of produced water. In the past, several estimates of the annual volume of produced water have been made, but none were highly accurate, nor are they current. The full-length paper describes a study conducted for the US Department of Energy (DOE) to develop accurate estimates of produced-water volumes for 2007. Introduction Produced-water-volume generation and management in the USA are not well characterized at a national level. The DOE asked Argonne National Laboratory to compile data on produced water associated with oil-and-gas production. Produced water is water from underground formations that is brought to the surface during oil-or-gas production. Because the water has been in contact with hydrocarbon-bearing formations, it contains some of the chemicals from the formations and hydrocarbons. It may include water from the reservoir, water previously injected into the formation, and any chemicals added during the production processes. Characteristics of Produced Water The physical and chemical properties of produced water vary considerably, depending on the geographic location of the field, the geologic formation from which the water was produced, and the type of hydrocarbon product being produced. Produced-water properties and volume also vary throughout the lifetime of a reservoir. For those sites where waterflooding is conducted, the properties and volumes of the produced water may vary dramatically because of injection of additional water into the formation to increase hydrocarbon production. The major constituents of concern are salt content, oil and grease (various organic compounds associated with hydrocarbons in the formation), inorganic and organic compounds introduced as chemical additives to improve drilling and production operations, and naturally occurring radioactive material. Produced water from gas production has characteristics that differ from those of produced water from oil production. In addition to formation water, water produced from gas production will contain condensed water, which is water that was in the vapor phase while in the reservoir but condenses into a liquid state in the production/separation system. Produced water from coalbed-methane (CBM) production differs from produced water from both oil and gas production. Oil and grease are less of a concern with CBM water than with other produced waters. To recover the methane in CBM reservoirs, the hydrostatic pressure that caused the adsorption of methane to the coal-bed is reduced through the removal of water from the reservoir through CBM wells. Characteristics of CBM water that may affect reuse are salinity, sodicity, and (to a lesser extent) iron, manganese, and boron.