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Oil-Base and Synthetic-Base Muds

Drilling Mud Tests

The field tests for rheology, mud density, and gel strength are accomplished in the same manner as outlined for water-based drilling mud. The main difference is that rheology is tested at a specific temperature, usually 120◦F or
150◦F. Because oils tend to thin with temperature, heating fluid is required and should be reported on the API Mud Report.
see our Drilling Fluids Books section

Sand Content
Sand content measurement is the same as for water-base drilling mud except that the mud’s base oil instead of water should be used for dilution. The sand content of oil-base mud is not generally tested.
HPHT Filtration The API filtration test result for oil-base drilling mud is usually zero. In relaxed filtrate oil-based muds, the API filtrate should be all oil. The API test does not indicate downhole filtration rates. The alternative high-temperature–high pressure (HTHP) filtration test will generally give a better indication of the fluid loss characteristics of a fluid under downhole temperatures The instruments for the HTHP filtration test consists essentially of a controlled pressure source, a cell designed towithstand a working pressure of at least 1,000 psi, a system for heating the cell, and a suitable frame to hold the cell and the heating system. For filtration tests at temperatures above 200◦F, a pressurized collection cell is attached to the delivery tube.
The filter cell is equipped with a thermometer well, oil-resistant gaskets, and a support for the filter paper (Whatman no. 50 or the equivalent). A valve on the filtrate delivery tube controls flow from the cell. A nonhazardous
gas such as nitrogen or carbon dioxide should be used as the pressure source. The test is usually performed at a temperature of 220 – 350◦F and a pressure of 500 psi (differential) over a 30-minute period. When other temperatures, pressures, or times are used, their values should be reported together with test results. If the cake compressibility is desired, the test should be repeated with pressures of 200 psi on the filter cell and
100 psi back pressure on the collection cell. The volume of oil collected at the end of the test should be doubled to correct to a surface area of 7.1 inches.

read also Testing of Drilling Systems

Electrical Stability
The electrical stability test indicates the stability of emulsions of water inoilmixtures. The emulsion tester consists of a reliable circuit using a source of variable AC current (or DC current in portable units) connected to strip electrodes . The voltage imposed across the electrodes can be increased until a predetermined amount of current flows through the drilling mud emulsion-breakdown point. Relative stability is indicated as the voltage at the breakdown point and is reported as the electric stability of the fluid on the daily API test report.

Liquids and Solids Content
Oil, water, and solids volume percent is determined by retort analysis as in a water-base drilling mud. More time is required to get a complete distillation of an oil mud than for a water mud. The corrected water phase volume, the volume percent of low-gravity solids, and the oil-to-water ratio can then be calculated.

The volume oil-to-water ratio can be found from the procedure below:

Oil fraction 100 × % by volume oil or synthetic oil / (% by volume oil or synthetic oil−% by volume water)

Chemical analysis procedures for nonaqueous fluids can be found in the API 13B bulletin available from the American Petroleum Institute.

Alkalinity and Lime Content (NAF)
The whole mud alkalinity test procedure is a titration method that measures the volume of standard acid required to react with the alkaline (basic) materials in an oil mud sample.
The alkalinity value is used to calculate the pounds per barrel of unreacted, “excess” lime in an oil mud. Excess alkaline materials, such as lime, help to stabilize the emulsion and neutralize carbon dioxide or hydrogen sulfide
acidic gases.

Total Salinity (Water-Phase Salinity [WAF] for NAF)
The salinity control ofNAFfluids is very important for stabilizing water-sensitive shales and clays. Depending on the ionic concentration of the shale waters and of the drilling mud water phase, an osmotic flow of pure water from the weaker
salt concentration (in shale) to the stronger salt concentration (in mud) will occur. This may cause dehydration of the shale and, consequently, affect its stabilization

Specialized Tests
Other, more advanced laboratory-based testing is commonly carried out on drilling fluids to determine treatments or to define contaminants. Some of the more advanced analytical tests routinely conducted on drilling fluids include:

Advanced Rheology and Suspension Analysis
FANN 50 — A laboratory test for rheology under temperature and moderate pressure (up to 1,000 psi and 500◦F).
FANN 70 — Laboratory test for rheology under high temperature and high pressure (up to 20,000 psi and 500◦F).
FANN 75 — Amore advanced computer-controlled version of the FANN 70 (up to 20,000 psi and 500◦F).

High-Angle Sag Test (HAST)
A laboratory test device to determine the suspension properties of a fluid in high-angle wellbores. This test is designed to evaluate particle setting characteristics of a fluid in deviated wells.

Drilling Mud
Salt Saturation Curves

Dynamic HAST
Laboratory test device to determine the suspension properties of a drilling fluid under high angle and dynamic conditions.

Specialized Filtration Testing
FANN 90 Dynamic filtration testing of a drilling fluid under pressure and temperature. This test determines if the fluid is properly conditioned to drill through highly permeable formations. The test results include two numbers: the dynamic filtration rate and the cake deposition index (CDI).
The dynamic filtration rate is calculated from the slope of the curve of volume versus time. The CDI, which reflects the erodability of the wall cake, is calculated from the slope of the curve of volume/time versus time. CDI and dynamic filtration rates are calculated using data collected after twenty minutes. The filtration media for the FAN 90 is a synthetic core. The core size can be sized for each application to optimize the filtration rate.

Particle-PluggingTest (PPT)
The PPT test is accomplishedwith a modified HPHT cell to examine sealing characteristics of a drilling fluid. The
PPT, sometimes known as the PPA (particle-plugging apparatus), is key when drilling in high-differential-pressure environments.

Aniline Point Test
Determine the aniline point of an oil-based fluid base oil. This test is critical to ensure elastomer compatibility when using nonaqueous fluids.

Particle-Size Distribution (PSD) Test
The PSD examines the volume and particle sizedistribution of solidsinafluid.This test is valuable indetermining
the type and size of solids control equipment that will be needed to properly clean a fluid of undesirable solids.

Luminescence Fingerprinting
This test is used to determine if contamination of a synthetic-based mud has occurredwith crude oil during drilling
operations.

Lubricity Testing
Various lubricity meters and devices are available to the industry to determine how lubricous a fluid is when exposed to steel or shale. In high-angle drilling applications, a highly lubricious fluid is desirable to allow proper transmission of weight to the bit and reduce side wall sticking tendencies.

Drilling Fluids

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Drilling Fluids

Drilling Fluid Definitions and General Functions

Results of research has shown that penetration rate and its response to weight on bit and rotary speed is highly dependent on the hydraulic horsepower reaching the formation at the bit. Because the drilling fluid flow rate sets the system pressure losses and these pressure losses set the hydraulic horsepower across the bit, it can be concluded that the drilling fluid is as important in determining drilling costs as all other “controllable” variables combined. Considering these factors, an optimum drilling fluid is properly formulated so that the flow rate necessary to clean the hole results in the proper hydraulic horsepower to clean the bit for the weight and rotary

Drilling Muds and Completion Systems

speed imposed to give the lowest cost, provided that this combination of variables results in a stable borehole which penetrates the desired target. This definition incorporates and places in perspective the five major functions of a drilling fluid.

Cool and Lubricate the Bit and Drill String

Considerable heat and friction is generated at the bit and between the drill string and wellbore during drilling operations. Contact between the drill string and wellbore can also create considerable torque during rotation and drag during trips. Circulating drilling fluid transports heat away from these frictional sites, reducing the chance of premature bit failure and pipe damage. The drilling fluid also lubricates the bit tooth penetration through the bottom hole debris into the rock and serves as a lubricant between the wellbore and drill string, reducing torque and drag.

Clean the Bit and the Bottom of the Hole

If the cuttings generated at the bit face are not immediately removed and started toward the surface, they will be ground very fine, stick to the bit, and in general retard effective penetration into uncut rock.

Suspend Solids and Transport Cuttings and Sloughing to the Surface Drilling fluids must have the capacity to suspend weight materials and drilled solids during connections, bit trips, and logging runs, or they will settle to the low side or bottom of the hole. Failure to suspend weight materials can result in a reduction in the drilling fluids density, which can lead to kicks and potential of a blowout.

The drilling fluid must be capable of transporting cuttings out of the hole at a reasonable velocity that minimizes their disintegration and incorporation as drilled solids into the drilling fluid system and able to release the cuttings at the surface for efficient removal. Failure to adequately clean the hole or to suspend drilled solids can contribute to hole problems such as fill on bottom after a trip, hole pack-off, lost returns, differentially stuck pipe, and inability to reach bottom with logging tools.

Factors influencing removal of cuttings and formation sloughing and solids suspension include

  • Density of the solids
  • Density of the drilling fluid
  • Rheological properties of the drilling fluid
  • Annular velocity
  • Hole angle
  • Slip velocity of the cuttings or sloughings

Stabilize the Wellbore and Control Subsurface Pressures

Borehole instability is a natural function of the unequal mechanical stresses and physical-chemical interactions and pressures created when supporting material and surfaces are exposed in the process of drilling a well. The drilling fluid must overcome the tendency for the hole to collapse from mechanical failure or from chemical interaction of the formation with the drilling fluid. The Earth’s pressure gradient at sea level is 0.465 psi/ft, which is equivalent to the height of a column of salt water with a density (1.07 SG) of 8.94 ppg.

In most drilling areas, the fresh water plus the solids incorporated into the water from drilling subsurface formations is sufficient to balance the formation pressures. However, it is common to experience abnormally pressured formations that require high-density drilling fluids to control the formation pressures. Failure to control downhole pressures can result in an influx of formation fluids, resulting in a kick or blowout. Borehole stability is also maintained or enhanced by controlling the loss of filtrate to permeable formations and by careful control of the chemical composition of the drilling fluid.

Most permeable formations have pore space openings too small to allow the passage of whole mud into the formation, but filtrate from the drilling fluid can enter the pore spaces. The rate at which the filtrate enters the formation depends on the pressure differential between the formation and the column of drilling fluid and the quality of the filter cake deposited on the formation face. Large volumes of drilling fluid filtrate and filtrates that are incompatible with the formation or formation fluids may destabilize the formation through hydration of shale and/or chemical interactions between components of the drilling fluid and the wellbore.

Drilling fluids that produce low-quality or thick filter cakes may also cause tight hole conditions, including stuck pipe, difficulty in running casing, and poor cement jobs.

Assist in the Gathering of Subsurface Geological Data and Formation Evaluation

Interpretation of surface geological data gathered through drilled cuttings, cores, and electrical logs is used to determine the commercial value of the zones penetrated. Invasion of these zones by the drilling fluid, its filtrate (oil or water) may mask or interfere with interpretation of data retrieved or prevent full commercial recovery of hydrocarbon.

Other Functions

In addition to the functions previously listed, the drilling fluid should be environmentally acceptable to the area inwhich it is used. It should be noncorrosive to tubulars being used in the drilling and completion operations. Most importantly, the drilling fluid should not damage the productive formations that are penetrated.

The functions described here are a few of the most obvious functions of a drilling fluid. Proper application of drilling fluids is the key to successfully drilling in various environments.

Classifications

a generalized classification of drilling fluids can be based on their fluid phase, alkalinity, dispersion, and type of chemicals used in the formulation and degrees of inhibition. In a broad sense, drilling fluids can be broken into five major categories.

Freshwater Muds—Dispersed Systems

The pH value of low-pH muds may range from 7.0 to 9.5. Low-pH muds include spud muds, bentonite-treated muds, natural muds, phosphatetreated muds, organic thinned muds (e.g., red muds, lignite muds, lignosulfonate muds), and organic colloid–treated muds. In this case, the lack of salinity of the water phase and the addition of chemical dispersants dictate the inclusion of these fluids in this broad category.

Inhibited Muds—Dispersed Systems

These are water-base drilling muds that repress the hydration and dispersion of clays through the inclusion of inhibiting ions such as calcium and salt. There are essentially four types of inhibited muds: lime muds (high pH), gypsum muds (low pH), seawater muds (unsaturated saltwater muds, low pH), and saturated saltwater muds (low pH). Newer-generation inhibited-dispersed fluids offer enhanced inhibitive performance and formation stabilization; these fluids include sodium silicate muds, formate brine-based fluids, and cationic polymer fluids.

Low Solids Muds—Nondispersed Systems

These muds contain less than 3–6% solids by volume, weight less than 9.5 lb/gal, and may be fresh or saltwater based. The typical low-solid systems are selective flocculent, minimum-solids muds, beneficiated clay muds, and low-solids polymer muds. Most low-solids drilling fluids are composed of waterwith varying quantities of bentonite and a polymer. The difference among low-solid systems lies in the various actions of different polymers.

Nonaqueous Fluids

Invert Emulsions Invert emulsions are formed when one liquid is dispersed as small droplets in another liquidwith which the dispersed liquid is immiscible. Mutually immiscible fluids, such as water and oil, can be emulsified by shear and the addition of surfactants. The suspending liquid is called the continuous phase, and the droplets are called the dispersed or discontinuous phase. There are two types of emulsions used in drilling fluids:

oil-in-water emulsions that have water as the continuous phase and oil as the dispersed phase and water-in-oil emulsions that have oil as the continuous phase and water as the dispersed phase (i.e., invert emulsions). Oil-Base Muds (nonaqueous fluid [NAF]) Oil-base muds contain oil (refined from crude such as diesel or synthetic-base oil) as the continuous phase and trace amounts of water as the dispersed phase. Oil-base muds generally contain less than 5% (by volume) water (which acts as a polar activator for organophilic clay), whereas invert emulsion fluids generally have more than 5% water in mud. Oil-base muds are usually a mixture of base oil, organophilic clay, and lignite or asphalt, and the filtrate is all oil.

References:
1. Drilling Equipment and Operation.
2. drilling Operation.