Drilling-fluid costs can constitute a significant fraction of the overall costs of drilling a well. Often the cost is quoted per unit length drilled, which takes into account any problems encountered (and avoided), such as stuck pipe. In many cases, the cost ascribed to the fluid also includes costs associated with solids control/management and waste disposal.
Thus, it is just as important to minimize costs associated with these two aspects as it is to ensure that the drilling fluid fulfills its primary functions [Young & Robinson]. Muds that require special attention and equipment to control the levels and types of solids frequently incur higher costs. Likewise, muds that generate waste fluid and cuttings, which must be hauled off (and perhaps treated) rather than discharged directly into the environment, generally incur higher costs.
Until recently, waste WBMs did not require any treatment and could be discharged directly into the environment. However, a number of components in WBMs are becoming increasingly restricted or prohibited. Chrome-containing materials, such as chrome lignosulfonates, are prohibited in many areas by governmental regulations. Tight restrictions are imposed in many areas on chloride, nitrate, and potassium salts, or, more generally, on the total electrical conductivity of the mud. In the North Sea, use of polyacrylamide polymers, such as partially hydrolyzed polyacrylamide (PHPA), is also severely restricted. OBMs tend to be restricted even more than WBMs, especially offshore, and in many places they can be used only if a zero discharge strategy (sometimes called a closed loop system) is adopted [Lal & Thurber].
On the other hand, SBMs often can be discharged directly into the sea if they meet certain toxicity/biodegradability criteria and, in the United States, do not create a sheen; as a result, though SBMs generally incur higher initial costs than OBMs, disposal costs for SBMs tend to be considerably less, which can make them more economical to run.
True foams contain at least 70% gas(usually N2,CO2,or air)at surface of the hole,while energized fluids, including aphrons, contain lesser amounts of gas.Aphrons are specially stabilized bubbles that function as a bridging or lost circulation material(LCM)to reduce mud losses to permeable and microfractured formation.Aqueous drilling fluids are generally dubbed water-based muds (WBMs), while nonaqueous drilling fluids (NAFs) are often referred to as oil-based muds (OBMs) or synthetic-based muds (SBMs). OBMs are based on NAFs that are distilled from crude oil; they include diesel, mineral oils, and refined linear paraffins (LPs). SBMs, which are also known as pseudo– oil-based muds, are based on chemical reaction products of common feedstock materials like ethylene; they include olefins, esters, and synthetic LPs.
Detailed classification schemes for liquid drilling fluids are employed that describe the composition of the fluids more precisely. One such classification scheme is shown in Figures 2.1 and 2.2. An even more precise classification scheme is described in Table 2.1, which includesthe mud systems most commonly used today, along with their principal components and general characteristics.
A drilling fluid, or mud, is any fluid that is used in a drilling operation in which that fluid is circulated or pumped from the surface, down the drill string, through the bit, and back to the surface via the annulus.
Drilling fluids satisfy many needs in their capacity to do the following
. Suspend cuttings (drilled solids), remove them from the bottom of the hole and the well bore, and release them at the surface
. Control formation pressure and maintain well-bore stability
. Seal permeable formations
. Cool, lubricate, and support the drilling assembly
. Transmit hydraulic energy to tools and bit
. Minimize reservoir damage
. Permit adequate formation evaluation
. Control corrosion
. Facilitate cementing and completion
. Minimize impact on the environment
. Inhibit gas hydrate formation
The most critical function that a drilling fluid performs is to minimizethe concentration of cuttings around the drill bit and throughout the well bore. Of course, in so doing, the fluid itself assumes this cuttings burden, and if the cuttings are not removed from the fluid, it very quickly loses its ability to clean the hole and creates thick filter cakes. To enable on-site recycling and reuse of the drilling fluid, cuttings must be continually and efficiently removed.
Polymer drilling fluids, synthetic oil–based drilling fluids, and other fluids with expensive additives provide a great incentive to use good solids-control procedures. However, minimizing the waste products from these expensive systems will also have a great impact on drilling costs. Most drilling operations have a targeted drilled-solids concentration. Failure to remove drilled solids with solids-control equipment leads to solids control with dilution. This creates excessive quantities of fluid that
must be handled as a waste product. If this fluid must be hauled from the location, the excess fluid becomes a large additional expense. Even if the fluid can be handled at the location, larger quantities of fluid frequently increase cost. This is discussed in depth in Chapter 15 on Dilution. Smaller quantities of waste products can significantly decrease the cost of a well. Decreasing the quantity of drilling fluid discarded with the drilled solids will decrease the cost of rig-site cleanup. Dilution
techniques for controlling drilled-solids concentrations greatly increase the quantity of waste products generated at a rig. This results in an additional expense that adds to the total cost of drilling.