GPRI Basics of Produced Water Management

In the oil and gas industry, standard water management operations include handling large volumes of water, both fresh water and brine water [2]. Drilling operations (onshore Texas) for the most part employ water-based drill fluids for well construction. In addition well completions including fracturing operations use very large amounts of water, some of which may be fresh water when injected downhole, but are mixed with formation fluids when flowing back to the surface. Finally, production operations use produced brine to enhance petroleum production and maintain reservoir pressure. Different well operations require different water management strategies to minimize waste and to protect the environment. Generally water needs and issues can be grouped into two categories, drilling and completion including stimulation (fracturing) operations and production operations. These are discussed in the following sections.

Water Produced During Drilling Operations

Drill fluids are specially formulated materials containing chemicals, solids, and rheological control agents designed to drill through rock matrices and return drill cuttings to the surface for discharge. Drilling fluid companies have specialists whose job it is to manage drill waste in E&P operations and under most conditions, excess water production has not been an issue at the well site. High performance drilling fluids, materials that are designed for low damage, high temperature, maximum wellbore stability etc, are so costly that most service companies return the used fluid back to the service facility where it is reconstituted and used again. Typically only about 2% of the volume of drilling fluids is lost or discharged in drill cuttings waste.

More and more frequently oil and gas operators find that environmental issues are one of the key factors to consider when preserving the environment in an area without disrupting the lives of nearby communities. New technology is being developed to allow fluid handling systems to be designed as a zero-discharge operation. Many of these techniques have been developed for the offshore industry [3].

The main byproducts from drilling operations are re-injected. However, some practices recover water from drilling operations in ways that allow waste disposal in an environmentally sound way. Waste recycling, bio-treatment, and temporary offsite treatment and disposal are the options in a waste-management strategy. In Venezuela’s Orinoco Basin it was reported [4] that during 5 years of operation, a total of approximately 41.5×104 m3 (greater than 100 MM lbs per year) of exploration and production (E&P) waste were handled and disposed of successfully without harm to the environment.

In Texas, “zero discharge” operations at well sites are the normal operating practices. The most important factor when considering drilling practices is that drill operations offer a potential use of recovered water from other oil field operations.

Water Produced from Well Fracturing Operations

There is another way to obtain fresh water resources from O&G activity – to reduce the volume of water used in drilling operations and in particular fracturing operations. In the past 5 years, a new drilling boom has begun in North Texas in a development known as the “Barnett Shale”. The resource [5,6] is a gas play that has become an economic drilling target because of technology advancements in fracturing technology. The reservoir was originally developed in Wise and Denton County Texas but has trended southward into Johnson County and neighboring areas. Figure 1 shows the spatial location of the development. The expected gas reserves in the Barnett Shale keep increasing with the most recent projection by the USGS (United States Geological Society) have been estimated at 26.2 tcf [7,8]. Currently there are over 3,500 producing wells in the Basin.

The magnitude of the O&G development puts the Barnett Shale as the largest gas development in the lower 48 states and rivals the North Slope of potential gas resources. (At a natural gas price of $5.00 per MCF (million cubic ft. this resource represents almost $140 billion dollars.). Tax revenues received by Tarrant, Denton and Wise County Texas are more than a billion dollars a year [9].

The technology of massive shale fracturing with fresh water has been adopted by all of the operators in the Shale and geologists believe that this trend is a long term shift in O&G production in Texas as the Barnett Shale play extends southwest and new shale resources being investigated in West Texas (Woodford Shale) [5,6] and in East Texas and Western Arkansas (Fayetteville Shale) [7]. If these new resources are to be exploited, then significant water resources will be used for fracturing operations.

Barnett Shale fracturing operations utilize massive hydraulic fracturing stages in horizontal wells, each stage being separated from the previous one. Wells in Johnson County (Spring 2006) are being fractured with more than 5 million gallons of water. This water, for the most part is coming from surface water supplies and municipal sources. While the communities involved are making a profit selling the water at residential rates, the residents of the community are upset because of this apparently profligate water use for O&G operations while their cities are on restricted water use because of the drought.

Figure 1 shows unconventional resource coal bed methane basins for the onshore U.S. Currently gas production from unconventional sources, including CBNG, accounts for almost 15% of daily U.S. production.

A number of groups are studying ways to re-use fracture return brine in subsequent operations. As of early 2006, no commercial operations have been established.

Water Produced During Production Operations

Oil and gas operations on leases that have been on production for extended time produce copious amounts of brine water along with the associated oil and gas. Produced water, (any water that is present in a reservoir with the hydrocarbon resource) is produced to the surface with the crude oil or natural gas. Not only in Texas but world-wide the oil and gas industry is experiencing increased volume of produced water handled in both onshore and offshore petroleum production operations. The resulting operational costs and environmental issues are a major concern, especially with the possibility of further reduction in the oil content allowed in the discharged water (offshore operations, as well as the fact that produced water contains a number of undesirable toxic components.

Figure 2 shows oil field produced water volume trends for each of the five major operating areas for Shell Oil. (1,000 m3 = 6289 bbls). The trend increases in each of the areas until (assumed) new technology can intervene.

For the United States, the U.S. Department of Energy estimated more than 18 billion barrels per year were generated from onshore wells in 2000, and similar volumes are generated today [12]. Offshore wells in the United States generate several hundred million barrels per year of produced water. Internationally, three barrels of water are produced for each barrel of oil. Production in the United States is more mature; the U.S average is about 7 barrels of water per barrel of oil. Closer to home, in Texas the Permian Basin averages more than 9 of water per barrel of oil and represents more than 400 million gallons of water per day processed and re-injected [13]. New technology is needed to forestall these trends.

To speed up the adoption of technology, the industry has established a number of techniques for handling produced water both in mature fields and in new and planned developments [14, 15]. These practices take into consideration the nature of the water, technology limitations, both emission to the atmosphere and discharges into the sea, nature of the discharges, safety concerns and cost, as well as establishing any environmental gains in each case. The integrated oil company Shell uses a systematic empirical ranking and indicator tool applied to the different aspects of the alternative options considered. Most operators, big and small handle produced water management in the same way. (Most often in Texas however, the option is brine injection back into the producing formation.)

Management of water issues is a major emphasis of the DOE’s Oil and Gas Environmental Program administered by the National Energy Technology Laboratory’s National Petroleum Technology Office [12, 16]. Water issues include several concerns; injection water, produced water (including Coalbed Natural Gas-CBNG) and its effects on the environment, treatment of waste water, and the availability of water in arid lands. NETL currently has 26 projects grouped under Water Management Approaches and Analysis, Water Management Technologies, and Coalbed Methane and Produced Water. The shared goal of all of these projects is to ensure that water produced through oil and gas development does not adversely impact the environment and that it is put to beneficial uses where possible.

Managing Produced Water

Figure 3 shows active oil and gas wells, most producing brine. Oil and gas operators re-inject practically all their brine into leases to provide pressure maintenance* and to sustain production. Mature leases gradually end up re-cycling water until the field reaches its economic limit. Many gas fields and smaller oil leases have produced water transported to commercial salt water disposal wells.

To handle produced water, the O&G industry operates a large number of injection wells to re-inject the water to maintain production. All wells in Texas are regulated [13, 17] whether by the Texas Commission on Environmental Quality (TCEQ) or the Texas Railroad Commission (TRC) Records of where produced water is currently being disposed and practices in different regions of the state are kept by the Texas Railroad Commission (RRC) organized into oil, gas, and water production for each district in the state. That data has been combined with United States Geologic Survey (USGS) databases [19]. The USGS database is extensive, compiled in the past 50 years on formation waters to characterize the type of brine that is being produced. Additionally costs of current methods of managing produced water have been obtained from operators and from companies that transport and dispose of brines in salt water disposal wells. Additional information on formation water and produced brine is also available from the West Texas Geological Society [20].

Produced Water Volumes and Composition

Figure 3 shows the statewide distribution of produced brines [13] Distribution of produced water is shown for three categories of brine. Approximately 1/3 of the sites represent brines with salinity less than 10,000 ppm TDS. This is brackish water and can be treated for only slightly more expense than brackish ground water resources in Texas. The advantage of this is that the cost of producing this water is zero (paid for by the oil and gas production). The degree of difficulty in treating this brackish water is discussed in the following section.

Brackish Water Produced in Texas Oil and Gas Wells

Many of the producing fields in Texas discharge water having less than 10,000 ppm tds. Figure 5, 6, and 7 are composite maps of the state divided into Water Planning Districts. Each district has a number of producing wells that discharge brackish water (<10,000 ppm tds), saline water (10,000 to 50,000 ppm tds), and hyper-saline water (>50,000 ppm tds). .The locations of the fields are shown on the Figures. In addition Appendix 1B contains a list of the fields alphabetically for each county in Texas that discharge brackish water.

The entries on the map in Figure 5, 6, and 7 do not contain all of the information listed in the U.S.G.S. data base. Appendix 1B contains a tabular list of the sites, with partial information from each location. There is not a 1:1 correspondence of the map to the tabular list as many of the locations do not have latitude and longitude position locations. For more detailed information, the USGS database should be referenced [18]. The best source for this information for those planning studies of desalination of produced water should refer to the records of each county being considered.

Figure 3. The map shows the location of active gas wells in Texas. There are approximately 300,000 oil and gas wells, 2/3 of these wells are on production. The majority of these wells produce water that is usually re-injected to maintain pressure and production.

Desalination of oil field brackish brine may be less expensive because of the disposal options available to the water treatment operator.

Figure 4 shows distribution of produced water sites in Texas. Approximately 1/3 of the sites represent brines with salinity less than 10,000 ppm TDS and can be classified as “brackish water”. Figures 4, 5 and 6 on the following pages contain well sites according to salinity superimposed on maps of the TWDB Regional Water Planning Groups. Detailed maps of wells producing brackish water in each Water Resource Planning District are provided in Appendix 2 (Volume 2).

More detailed maps derived from GIS data are contained in Appendix 2 for each of the TWDB regional water planning regions. The solids circles represent oil or gas leases producing brine with less than 10,000 TDS brine. The database containing these locations was derived from the United States Geologic Survey database and updated with additional information from the West Texas Geological Society.

The charts in Appendix 2 also show the locations of impaired streams in Texas, a possible place where fresh water from desalination can be directed. More discussion is contained in a later section of this report.

BASICS OF PRODUCED WATER MANAGEMENT