There are a limited number of options for dealing with drilling waste generated in an offshore environment. The drilling waste can be discharged to the ocean (direct discharge), injected into the ground beneath the sea, or taken to shore for commercial disposal or a landbased disposal option.
Direct discharge is the most common mode of disposal for cuttings and waste drilling fluids generated during offshore drilling operations. Directly discharging drilling waste is inexpensive and simplifies operations. But, in recent years, increasing attention has been paid to environmental risks posed by this activity. It is now recognized that there may be some long-term liability associated with discharging, even if water-based fluid is used.
Direct discharge is needed when drilling with water-based fluids due to the large quantity of waste associated with this activity. Besides generating cuttings and associated fluid, drilling with water-based fluid generates relatively large volumes of waste fluid. This is due, in part, to the relative intolerance of water-based fluid to solids buildup in the active
system. It is very hard to control the desired properties of water-based fluid with a content of low-gravity solids (drilled solids) greater than 10%, and penetration rate will be adversely affected above 5%. Due to the sensitivity of water-based fluid to low-gravity drilled solids, a ‘‘dump and dilute’’ strategy may be adopted. Dumping whole, dirty fluid may create eight times the amount of waste created by the drilled cuttings.
Switching to oil- or synthetic-based drilling fluid will reduce the total amount of drilling waste generated. These NAFs are much more solids tolerant, and cuttings are not degraded as much as with WBM. The net result is that dumping of whole fluid is usually not needed.
In the last 20 years, cuttings generated while drilling with diesel-based fluid systems have been considered to be unsuitable for discharge. Other NAFs with drilling-performance benefits approaching diesel-based systems have been developed. While using some of these systems, cuttings
may be discharged with certain limitations in many parts of the world. With NAFs that discharge cuttings, the associated fluid will be lost. Most of these fluids are supplied on a rental basis. The cost of any fluid not returned will be charged to the operator, which has become a major cost.
Injection involves making a suitable slurry out of the waste generated during drilling operations. This solids-laden slurry is pumped into the formation at pressures exceeding the fracture. Since this is the only disposal method not involving the surface or the sea bottom, waste streams that would be undesirable to surface-dispose of could be safely disposed of by injection. However, in the United States, only exempt
waste can be injected. Nonexempt waste must be taken to an appropriate and approved UIC (underground injection control) well.
The use of injection as a method of disposal in offshore drilling operations has a history of mixed results. The first obstacle is having a conduit into a receiving formation. The slurry to be injected can be pumped down the inside of tubing or casing (through tubing injection), or it can be pumped down an annulus between casing strings into an open formation. Whichever method is used, the receiving formation must be isolated from the surface and other zones, especially up the cemented annulus. In many drilling operations, a conduit does not exist. The previous annuli have been cemented to surface, another well bore is not available, or a potential conduit simply does not exist. At other times, a satisfactory receiving formation does not exist.
Weak or unconsolidated sands are preferred as injection target. The sand can fluidize and repack, accommodating very large volumes of waste. Dedicated injection wells are preferred to annuli because the wells can be worked over if plugged by cuttings. Careful geotechnical surveys should be done to choose an appropriate zone. The zone must have a good seal above it, and the pipe must have a premium cement job.
If injection is to be used, then slurry must be made from the fluid and cuttings. The fluid and waste fluids are collected into slurry tanks to make the slurry. These slurry tanks are circulated with special slurry pumps designed to break up particles into natural grain sizes. If more fluid is needed because the slurry is too thick, then seawater can be added. The fluid may be too thin if excessive amounts of water are collected in the waste stream or if the mixing is insufficient. Frequently a shaker is used prior to the slurry tanks to prevent large particles or junk from entering the slurry tanks. In addition, there is a suction line screen to protect the pumps. There are usually two or three slurry tanks of 100- to 150-bbl capacity. This large volumetric capacity may be needed to handle large hole drilling.
Weight (or space) limitations on the rig or platform frequently pose problems. Generally, batches of about 300 bbl of slurry are made (this is limited mainly by space and weight criteria). If 100 bbl of seawater are pumped before and after the slurry, then the total volume of each injection would be 500 bbl. Total slurry and equipment weight may be between 125 and 150 tons, which includes the slurry holding tanks in addition to the slurry skid. The footprint for the equipment may be as much as 40 feet wide by 90 to 120 feet long, depending on the equipment required. However, with a little innovation, the weight and space problems can be overcome.
The final problem is rate of waste generation. Offshore there is not a great deal of space in which to collect waste. For example, if 8-1⁄2 inch hole is being drilled, then drilling 200 feet per tour would generate about 30 bbl of waste cuttings. An additional 50 bbl of oily wash water might also be generated. Total slurry volume would be about 100 bbl per tour. However, total slurry volume for 400 feet of 12-1⁄4 inch hole in a tour would be about 300 bbl. Similarly, 500 feet of 17-1⁄2 inches may require handling as much as 1000 bbl of total slurry. For the large jobs, it is advantageous to have some storage (buffer) for generated waste. On the other hand, the cuttings from an 81⁄2 inch hole can be collected in boxes to be slurried and injected later while drilling the 6-inch hole section. This may save rental cost on the slurry equipment during the slower drilling intervals and more fully utilize the rental equipment.
Collection and Transport to Shore
If discharge is not allowed or desired and injection is not possible, then the drilling waste must be collected and transported to shore for treatment or disposal. Generally, commercial disposal operations have been established in areas with supporting infrastructure. If no commercial
operations have been established, then company-operated land disposal options must be implemented.
Commercial disposal processes have been established in two main areas: the U.S. Gulf Coast and various countries bordering the North Sea. These processes will be described in order to establish a baseline of current commercial practices. Just because the commercial process exists does not mean that individual operators approve of the process or that long-term liabilities do not exist. However, it is possible that in a remote area with no onshore infrastructure for handling waste fluid and cuttings, some sort of commercial activity might be mimicked or encouraged.
At the present time in the Gulf Coast, all waste coming to shore from offshore drilling activities (approximately 6 million bbl per year) is handled by commercial facilities. It is possible for companies to permit, own, and operate their own disposal facilities, but it has not been done to date.
In general, fluid (mostly oil base) and cuttings returned to shore for disposal are separated into solid and liquid fractions. The liquid fraction is generally injected in a disposal well. The solid fraction is generally disposed of similar to land farming or converted to a dirtlike product that can be used.
One commercial disposal service provider in the Gulf Coast area operates several strategically placed waterfront waste receiving/transfer stations in Louisiana and Texas. The company sends material from these stations to four processing/disposal facilities in Texas. The waste fluid and cuttings received at any of the receiving/transfer facilities is offloaded into Coast Guardapproved (double hull construction) hopper barges for temporary storage. They can dump cuttings from boxes, receive waste from trucks into sumps, and pump off boat tanks. The filled hopper barges (possibly filled with multiple operators’ waste) are transported from the transfer stations to the main/central facility to be offloaded for processing, recycling, and/or disposal.
At the processing facility, reclaimed components from spent drilling fluids may be conditioned into recycled drilling fluids and reused for other drilling operations, although this is a minor amount. Nonreusable liquids and solids are transported via truck to one of the company’s injection wells. Slurries, containing up to 15% solids, are injected into porous geological formations below fracture pressure (these are typically depleted, subpressured wells). Typically, 20% of the fluid waste goes to reuse and 80% is injected.
A portion of the solids reclaimed at the processing facility are reused as daily cover in municipal sanitary landfills, under authority of the Texas Railroad Commission and the Texas Commission on Environmental Quality (TCEQ). The solids (dirt) used in this manner must meet criteria for landfill cover stipulated by the TCEQ.
Another company uses a process of collection and transfer similar to the one described, but differs in that it uses a salt cavern as a disposal site. Mud and cuttings are pumped into the salt cavern via a largediameter tubing string. The brine in the salt cavern is displaced to a saltwater storage system up the annulus between the tubing string and casing. The brine is then injected into a permitted saltwater disposal well. The oil contained in the cuttings floats to the top of the heavier brine in the cavern, forming an oil blanket. This oil blanket prevents erosion of the cavern ceiling.
Commercial disposal processes in the North Sea area tend to focus on oil removal from the cuttings. The oil is intended to be reused, either as drilling fluid makeup or some other purpose, such as a fuel source. Currently, only about 30% of the recovered oil (fluid) is being reused. The other 70% is being used for fuel material. The cuttings (after de-oiling) are sent to landfills. Thermal desorption is used to de-oil the cuttings (refer to the Treatment Techniques section later in this chapter for a discussion of thermal desorption).
Commercial operations in the developed areas of the Gulf Coast and the North Sea rely on certain infrastructure or systems that have been established. For instance, landfills are lined and daily cover is used. In many overseas areas, landfills may not be lined and the contents may be burned on a periodic basis. This poses considerable liability if an attempt is made to use them anyway. Also, injection wells to handle liquid being brought to shore are rarely available overseas.