Plant design allows drillers to reuse and recycle OBM

Oil-based mud-Conclusion

Iskander S. Hanna
Saudi Aramco
Dhahran

Salim A. Abukhamsin
Saudi Aramco
Dhahran

• Size Justification for storage/mixing [120,866 bytes]

Oil-based mud (OBM) plants, designed to treat used OBM from offshore rigs, will reduce the environmental impact by allowing drillers to reuse and recycle drilling fluids.

This conclusion of a two-part series provides specifications for an OBM facility and describes the chemical make up of OBM constituents.

The mud-handling facility (Fig. 1 [172,120 bytes]) is intended to receive, process, store, and mix mud on a batch basis. More specifically, the plant will:

1. Receive and store used OBM transported by workboats
2. Remove solids from the used mud and provide storage for the solids and the liquid fractions
3. Mix new mud from diesel or low-toxicity oil, brine, and reclaimed mud and chemicals
4. Store diesel or low-toxicity oil, brine, and treated/reconditioned OBM.

Workboats transporting the used mud from the offshore drilling rigs will dock at the pier. Each workboat will then transport a load of about 2,000 bbl of used mud. The used mud will then be pumped from the workboat's mud tanks to the used-mud receiving tank with the workboat's pump.

The offloading pump capacity for a typical workboat is 350 gpm, or 500 bbl/hr. The used-mud storage tanks will have a capacity of 1,000 bbl, allowing for 30 min retention time. The used-mud receiving tank and its agitation equipment will be located close to dock edge.

This equipment is to be contained in a dike or walled area to prevent spillage in the marine environment. The used mud will then be pumped to the used-mud storage tanks. The used-mud storage tanks will be designed to store a minimum of one workboat shipment of 2,000 bbl.

Solid size reduction

Equipment should be installed in the plant from which a series of procedures will reduce particle content size. The process begins with a transfer of OBM from the used-mud storage tank, using suction from the solids-control feed pump.

The dirty mud can be transferred through the facility at rates between 600 and 900 gpm with the discharge flow from the solids control feed pump passing through a fine-screened shale shaker. In tandem, a built-in desilter, typically fitted with a 200 to 300-mesh interchangeable screen, will be used.

The shale shaker should be mounted over the mud-treating tank. The shale shaker will reclaim the liquid while recovering and drying the solids from the desilter underflows. The 200-mesh screen will allow solids removal of 75 microns (µ) and larger while the wet solids retained on the screen flows into a bin.

The liquid underflow will be collected in the mud-treating tank. The desilter will take the 75-µ screened mud and further reduce the particle sizes to 15-20 µ.

The cut point of a 4-in. cone desilter is between 15 and 20 µ, while the cut point of a 2-in. cone desilter is 10 µ. Further mud treatment is accomplished by sending the mud through the centrifuge.

The centrifuge will take the 15 to 20-µ mud and further remove fines that are 3 µ or larger. The centrifuge feed pump will then take suction from the mud-treating tank and discharge it to the centrifuge.

Rates through the centrifuge must be controlled in a range between 25 and 50 gpm to effectively remove solids. The centrifuge should be a slow-speed, high-volume unit, designed to remove all solids that are 3 µ and larger.

The centrifuge will take suction through the centrifuge feed pump while the liquid discharge from the centrifuge will collect either back at the mud-treating tank or flow directly to the mudmixing tank.

It may be necessary to recirculate the mud through the system or from mix tank to mix tank in order to achieve the desired mud weight or separation down to 3 µ. The wet solids discharge from the shale shaker and centrifuge will be collected in bins or skips.

By removing the fines and the calcium carbonate weight material, the initial volume of a 10-ppg used mud will be reduced by 30%.

The solids control equipment-shale shaker, desilter, and centrifuge-will be mounted on structural steel. A walkway system will be installed so all solids-control equipment can be operated and maintained easily.

OBM transfer

Once the desired amount of solids is removed, the used mud can be reconditioned. Required volumes of diesel oil or kerosine, brine, and reconditioned mud will be measured by tank gauging. Premeasured mud additives such as emulsifiers will be added to the mud through the mixing hoppers or directly dumped into the mixing tank.

The mixing tanks feed pump will take suction from any of the reclaimed mud, new brine, diesel, or kerosine tanks. This pump will be sized to fill one mixing tank in 1 hr (500 bbl/hr). The mixing tank feed pump will then discharge the fluid to two 500-bbl mixing tanks, designed to hold corrosive liquids.

Each mixing tank will have two paddle mixers installed and will be sized to turn over the contents of the tank in 1 hr. In case of an offspecification mud batch, a slop tank would be required to receive the batch.

One of the mud-storage tanks should be designated as a slop tank. Two mixing or shearing hoppers will be installed and the hoppers will be piped so that they can deliver mixed liquids to either mixing tank. The top of the hoppers must be accessible by forklifts used to lift sacks or drums of additives for mixing.

The new or reconditioned mud-feed pump, with a capacity of 500 bbl/hr will deliver the mud mixture to the workboats or back to the storage tanks. A pipeway covered with grading will contain both main and standby piping, used to transfer used mud from the receiving tank to the storage tank. The piping will be flanged for maintenance.

The piping that transfers the new or reconditioned mud from the reclaimed mud-storage tanks to the loading boats on the docks will be installed in the same pipeway alongside the piping that transfers the used mud. This piping will also be flanged for maintenance.

Provision should be made to flush out all the lines used in the transfer of weighted muds. A walkway system will be required along the top of the mixing tanks for mud sampling. An external simple level indicator will be required on the mixing tanks (pit bar gauge). Raw water will be piped to the mud-mixing tanks for cleaning and for mixing brine.

Storage facilities

The storage tank's transfer pump will take suction from either the mud-treating tank or the mud-mixing tank. The discharge flow from the storage tanks' transfer pump will move reclaimed liquids to the reconditioned-mud storage tanks.

Four cylindrical, cone-roofed tanks, each with 1,000 bbl capacity, will be required for storing the reconditioned mud. The reconditioned mud-storage tanks will have agitation equipment such as jet nozzles and rings to prevent solids settlement. The agitation equipment will be sized to turn over the contents of a tank in 2 hr.

A 500-bbl cylindrical, cone-roofed storage tank will be required for storing new brine. This tank will be designed to hold corrosive liquids and withstand high exothermic-reaction temperatures of about 200° F. Fusion-bond epoxy coating or equivalent will be used for internal tank protection.

Four cylindrical, cone-roofed tanks, each with 1,000 bbl capacity, will be required for storing the diesel or lowtoxicity oil. These tanks will not be designed to hold corrosive liquid. It will be necessary for all enclosed tanks to have proper ventilation.

A walkway system will be required so that all storage tanks can be gauged and visually inspected through a top hatch. An external, simple-level indicator will be required on the storage tank (pit-bar gauge).

The flow rates for the transfer activities and the justification of tank volumes depend on the facilities design parameters, equipment specifications, and fluid type (Table 1 [44,302 bytes]).

General requirements

The general requirements and design data are as follows:

1. The overall size should be about 400 ft by 400 ft.
2. Containment walls or dikes should be installed around all tanks and operating equipment.
3. A small building, about 15 ft by 25 ft in size, should be installed for mud testing. This building should also include a change room for 12 people and a small office for the mud engineer.
4. A firewater system should be installed to cover the mud-handling facilities.
5. Water flush hoses should be available to clean all equipment.
6. Eye-wash systems and showers should be installed next to the mixing tanks, ensuring personnel safety.
7. All electrical equipment should be explosionproof (Class I, Group D, Division 1).
8. The cutting containers should be designed for easy transportation from the drilling rig to workboat deck, and from the workboat to pier. Fifty 20-bbl containers should be provided.
9. Utility outlet for fresh water, raw water, and diesel located next to the dock. Utility air should also be available.
10. The mud-handling facility for all tanks and equipment should be skid mounted on structural steel for ease of transportation.

OBM chemistry

Because OBM contains toxic substances that affect handling and equipment design, it is important to understand the basic chemistry behind its composition. OBMs consist of oil (diesel or low-toxicity); additives such as emulsifiers, wetting agents, filtration control additives, and gelling agents; and calcium chloride or sodium chloride brines.

Oil and aqueous phases

Oil is the continuous phase within oil muds. The most common types are No. 2 diesels, low-toxicity mineral oils, and kerosine (Table 2 [36,652 bytes]). Crude oil is relatively inexpensive and often available but may need toping to minimize flammability. A flash point greater than 180° F. is advisable. Crude also contains native asphaltenes and resins that can interfere with other additives.¹

The emulsified water, or aqueous phase in oil muds, can be fresh or contain dissolved salts. Calcium chloride is the most common salt used, although sodium chloride (NaCl), seawater, and lease brine are known. The choice is dictated by formation requirements and economics.

When salt or any substance hydrates to water, while the concentration of ions or hydrated molecules increases, the average freedom of the water molecules decreases, as does its activity.

If two solutions of different activities are separated by a semipermeable membrane (Fig. 2 [72,047 bytes]), allowing water molecules to freely pass while inhibiting salt molecules, it has been found that water molecules in the solution of a higher activity will diffuse into lower activity solutions, but not the ions.

If the chamber is sealed with the low-activity solution, it has also been found that the diffusing water increases the pressure within the chamber. This pressure is defined as the osmotic pressure.

Semipermeable membranes are created between emulsified water droplets in water/oil emulsions. Unless the activities are equal, an osmotic imbalance or potential exists and water will migrate. This also occurs with hydratable shale (Fig. 3 [76,697 bytes]).

The osmotive pressure of a calcium chloride-saturated brine may reach 24,400 psi.²

Emulsions, surfactants

Liquids that are not soluble in each other are called immiscible (water and oil). When immiscible liquids are mixed vigorously, one liquid will be suspended or dispersed as droplets in the other liquid. These two-phase systems are called emulsions.

The dispersed or suspended liquid is called the internal or dispersed phase. The other liquid is called the external or continuous phase. The most common types of emulsions are oil-inwater and water-in-oil (invert emulsion).

Examples of oil-in-water emulsions include milk and mayonnaise. Examples of water-in-oil emulsions include grease, OBMs, and inverts. A mixer can form a mechanical emulsion between two pure liquids such as water and hydrocarbon, but the emulsion breaks and the two phases separate when the agitation ceases. In order to form a stable emulsion, a third component is necessary.

Surface-active compounds are compounds that orient at interfaces or surfaces, serving to lower the surface (interfacial) tension. Surface-active compounds are often called surfactants.

These structures are called amphipathic to indicate the dual character of these compounds. Ivory soap is an example of a surfactant. Amphipathic compounds have both a hydrophilic head that is polar and ionized, and an oleophilic tail that is nonpolar (Fig. 4 [119,260 bytes]).

Temperature increases the number of droplet collisions and decreases the stability of emulsions. Imposing an electrical field across an emulsion will also tend to break the emulsion. Increasing the viscosity of the external phase will decrease the number of collisions and stabilize the emulsion.

Soaps, colloids, asphalts

Soaps are formed from an alkaline material such as caustic soda (NaOH) and longchain organic acid such as a tallow fatty acid. The caustic supplies a cation, Na+, also referred to as a counter ion, which balances the negatively charged hydrophilic head.

Soaps form good emulsifiers in high-pH or over-based systems, but are less useful at a lower pH. They emulsify fresh water well, but show poor electrolyte tolerance. In addition, soaps lose effectiveness at low activity level. All soaps tend to require additional emulsifiers at high solids concentration.

Colloids or organophilic clay form by reacting a quaternary chloride with sodium bentonite. The cationic quaternary replaces a sodium ion on the surface of the bentonite. This effectively renders the surface oil wettable, allows the hydrocarbon to wet and penetrate the clay lattice structure, swelling the organophilic clay to dispersion.

While organophilic bentonite is the most common form, hectorite and sepiolite are also known. Organo philic clays are excellent gelling agents in oil, especially when suspending weighting materials. They are relatively inexpensive but have only moderately good thermal stability. They are best dispersed if alcohol or ketones are present.

Asphalts are primarily used for fluid-loss control. The most commonly encountered asphalts are those naturally present in crude, including gilsonite and blown asphalt. Asphalt also functions as a shale stabilizer and viscosifier at higher concentrations.

Inverted oil mud

Inverted emulsion oil muds form a very slick mud in which the degree of inhibition is controlled by adjusting the chloride content of the water phase. When the chloride content is slightly higher than the chlorides within the connate water, shale inhibition will occur.

When the chlorides content is much higher, it will remove the water from the shale, toughening the wall of the hole. However, this will dilute the mud in extreme cases and it will become necessary to haul away the excess mud.

Holes are usually drilled in-gauge with inverted emulsion oil mud because the shales are highly inhibitive and because the annular mud flow is laminar, under normal flow rates. Inverted oil mud is very stable at high temperatures, up to 520° F.

Formation damage can be severe, but because the damage is shallow, inverted oil mud is considered to be the least damaging of any mud-to-water sensitive formations. When logging, the proper tools must be used. The SP log must be replaced with a gamma ray log, and an ordinary dipmeter will not properly log in inverted emulsion oil muds.

Inverted emulsion oil mud can be used for all density ranges above 8.2 ppg. Producing intervals should not be acidized if they have been exposed to inverted emulsion oil mud, unless the interval has been cleaned up through inflow of producing fluids. A mixture of acid and inverted emulsion oil mud will yield a very thick grease.

Mud toxicity

Regulatory agencies require standard tests and request data concerning drilling fluid/marine organism bioassays. The biological assessment or bioassay comprises a test designed to measure the effect of a chemical on a test population of organisms.^{3 4}

The effect may be a physiological or biochemical parameter, such as growth rate, respiration, or enzyme activity, or, as in the case of drilling fluids, lethality becomes the measured end point.

To quantify the effect of a chemical on a population, groups of organisms are exposed to different concentrations of a chemical for a predetermined interval. A basic premise in toxicology is that for each incremental dose or concentration above a threshold limit, there is a corresponding change in some measurable response of the organism.

The concentration at which 50% of the test population responds is known as the EC 50 (effective concentration 50%). When death is the measured response, it is called the LC 50 (lethal concentration 50%).

A high LC 50 value indicates low toxicity, and a low LC 50 value indicates a high degree of toxicity. The 50% value is generally chosen because it represents the response of the average organism to the toxic exposure, thus providing the greatest predictive ability.

Bioassay procedure

The bioassay for a drilling fluids test divides the drilling fluid into three phases:

1. Liquid soluble phase
2. Suspended particulate phase
3. Solid phase.

These phases represent what is anticipated when drilling fluids are discharged near the surface. Certain drilling fluid components are water soluble.

Serial dilutions to the suspended particulate phase and the solid phase are made for the procedure. The filtered phase and the solid particulate phase of a 1:4 slurry represent a 100% concentration or 1 million ppm. These two phases of drilling fluids, used in the test procedure, expose mysid shrimp (Mysidopsis bahia) for 96 hr to determine the LC 50.

The hard clam (Mercenaria mercenania) is also exposed to the solid phase for 10 days to determine its survival percentage. Results of these experiments usually provide LC 50s ranging from 25,000 ppm to greater than 1 million ppm of the phase for a variety of muds.

Table 3 [33,821 bytes] presents a classification of toxicity grades. There are other tests for toxicity, but the LC 50 test is used most often in the oil and gas industry. Table 4 [18,375 bytes] shows the toxicity for several OBM products.

References

1. Mobil Drilling Services, "Oil-Base Mud Manual," August 1985.
2. NL Baroid/NL Industries Inc., "Manual of Drilling Fluids," 1979.
3. Duke, T.W., Parrish, P.R., Montgomery, R.M., Macauley, S.D., Macauley, J.M., and Cripe, G.M., "Acute toxicity of eight laboratoryprepared generic drilling fluids to mysids (mysidopsis)," EPA Project Summary, EPA600/S384067, 1984.
4. Environmental Protection Agency, "Draft General NPDES Permit for Oil and Gas Operations in Portions of the Gulf of Mexico-Part II," July 1985.

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