Soil Testing Equipment

Results of research has shown that penetration rate and its response to weight on bit and rotary speed ishighly dependent on the hydraulic horsepower reaching the formation at the bit. Because the drilling fluid flowrate 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 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.

Considerable heat and friction is generated at the bit and between the drill string and wellbore during drilling operations. Contact between the drill string andwellbore 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 bitfailure 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.

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.

Drilling fluids must have the capacity to suspend weight materials and drilled solids during connections, bittrips, 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 theirdisintegration 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 sloughings 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

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 fluidmust overcome the tendency for the hole to collapse frommechanical failure or fromchemical 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 formationpressures.

However, it is common to experience abnormallypressured formations that require high-density drilling fluids to control the formation pressures. Failure to control downhole pressures can result in aninflux of formation fluids, resulting inakick or blowout. Borehole stabilityis also maintained or enhanced by controlling the loss of filtrate to permeble 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 alsocause tight hole conditions, including stuck pipe, difficulty in running casing, and poor cement jobs

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.

1.1.7 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 fewof themost obvious functions of a drilling fluid. Proper application of drilling fluids is the key to successfully drilling in various environments.

Ageneralized classification of drilling fluids can be based on theirfluid 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.

1.2.1 Freshwater Muds—Dispersed Systems
The pHvalue of low-pHmudsmay range from7.0 to 9.5. Low-pHmuds include spud muds, bentonite-treated muds, natural muds, phosphate treated muds, organicthinned muds (e.g., red muds, lignite muds, lignosulfonatemuds), and organic colloid–treatedmuds. In this case, the lack of salinity of the water phase and the addition of chemical dispersants dictate the inclusion of these fluids inthis broad category.

1.2.2 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), gypsummuds (lowpH), seawatermuds (unsaturated saltwater muds, lowpH), and saturated saltwatermuds (lowpH).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.

1.2.3 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 ofwaterwith varying quantities of bentonite and a polymer. The difference among low-solid systems lies in the various actions of different polymers.

1.2.4 Non aqueous Fluids
Invert Emulsions Invert emulsions are formed when one liquid isdis persed as small droplets in another liquidwith which the dispersed liquidis 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 indrilling 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 andwater as the dispersed phase (i.e., invert emulsions) Oil-Base Muds (nonaqueous fluid [NAF]) Oil-base muds containoil (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.

To properly control the hole cleaning, suspension, and filtration properties of a drilling fluid, testing of the fluid properties is done on a daily basis. Most tests are conducted at the rigsite, and procedures are set forth
in the API RPB13B. Testing of water-based fluids and nonaqueous fluids can be similar, but variations of procedures occur due to the nature of the fluidbeing tested.

1.3.1 Water-Base Muds Testing
To accurately determine the physical properties of water-based drilling fluids, examination of the fluid is required in a field laboratory setting. In many cases, this consists of a fewsimple tests conducted by the derrickman or mud Engineer at the rigsite. The procedures for conducting all routine drilling fluid testing can be found in the American Petroleum Institute’s API RPB13B.

within ±0.1 lb/gal or ±0.5 lb/ftDensity Often referredto as themudweight,densitymay be expressedas pounds per gallon (lb/gal), pounds per cubic foot (lb/ft3), specific gravity (SG) or pressure gradient (psi/ft). Any instrument of sufficient accuracy 3 may be used. The mud balance is the instrument most commonly used. The weight of a mud cup attached to one end of the beam is balanced on the other end by a fixed counterweight
and a rider free to move along a graduated scale. The density of the fluid isadirect reading from the scales located on both sides of the mud balance.

Marsh Funnel Viscosity Mud viscosity is a measure of the mud’s resis- tance toflow.Theprimary function ofdrillingfluidviscosity is a to transport cuttings to the surface and suspend weighing materials. Viscosity must
be high enough that the weighting material will remain suspended but low enough to permit sand and cuttings to settle out and entrained gas to escape at the surface. Excessive viscosity can create high pump pressure, which magnifies the swab or surge effect during tripping operations. The control of equivalent circulating density (ECD) is always a prime concern when managing the viscosity of a drilling fluid. The Marsh funnel is a rig site instrument used tomeasure funnel viscosity. The funnel isdimensioned so that by following standard procedures, the outflow time of 1 qt (946ml) of freshwater at a temperature of 70±5◦F is26±0.5 seconds A graduated cup is used as a receiver.

Direct Indicating Viscometer This is a rotational type instrument powered by an electricmotor or by a hand crank .Mud is contained in the annular space between two cylinders. The outer cylinder or rotor sleeve is driven at a constant rotational velocity; its rotation in the mud produces a torque on the inner cylinder or bob. A torsion spring restrains the movement of the bob. A dial attached to the bob indicates its displacement on a direct reading scale. Instrument constraints have been adjusted

so that plasticviscosity, apparent viscosity, and yield point are obtained by using readings from rotor sleeve speeds of 300 and 600 rpm. Plasticviscosity (PV) in centipoise is equal to the 600 rpm dial reading minus the 300 rpm dial reading. Yield point (YP), in pounds per 100 ft 2, is equal to the 300-rpm dial reading minus the plasticviscosity. Apparent viscosity in centipoise is equal to the 600-rpm reading, divided by two.

Gel Strength Gel strength is a measure of the inter-particle forces and indicates the gelling thatwill occurwhen circulation is stopped. This property prevents the cuttings from setting in the hole. High pump pressure is generally required to “break” circulation inahigh-gel mud. Gel strength is measured inunits of lbf/100 ft 2.This reading is obtained by noting the maximum dial deflection when the rotational viscometer is turned at a low rotor speed (3 rpm) after the mud has remained static for some period of time (10 seconds, 10 minutes, or 30 minutes). If the mud is allowed to remain static in the viscometer for a period of 10 seconds, the maximum dial deflection obtainedwhen the viscometer is turned on is reported as the initial gel on the API mud report form. If the mud is allowed to remain static for 10minutes, themaximumdial deflection is reported as the 10-min gel. The same device is used to determine gel strength that is used to determine the plasticviscosity and yield point, the Variable Speed Rheometer/Viscometer. 

API Filtration Astandard API filter press is used to determine the filter cake building characteristics and filtration of a drilling fluid(Figure 1.4). TheAPI filter press consists of a cylindricalmud chambermade ofmaterials resistant to strongly alkaline solutions.Afilter paper is placed on the bottom of the chamber just above a suitable support. The total filtration area is 7.1 (±0.1) in. 2. Below the support is a drain tube for discharging the filtrate into a graduated cylinder. The entire assembly is supported by a stand so 100-psi pressure can be applied to the mud sample in the chamber.At the end of the 30-minute filtration time, the volume of filtrate is reported as API filtration. inmilliliters. To obtain correlative results, one thickness of the proper 9-cm filter paper—Whatman No. 50, S&S No. 5765, or the equivalent—must be used. Thickness of the filter cake is measured and reported in 32nd of an inch. The cake isvisually examined, and its consistency is reported using such notations as “hard,” “soft,” tough,” ’‘rubbery,” or “firm.”

Sand Content The sand content indrilling fluids is determined using a 200-mesh sand sieve screen 2 inches indiameter, a funnel to fit the screen, and a glass-sand graduated measuring tube (Figure 1.5). The measuring
tube is marked to indicate the volume of “mud to be added,” water to be added and to directly read the volume of sand on the bottom of the tube.Sand content of themud is reported in percent by volume.Also reported is thepoint of sampling (e.g.,flowline, shale shaker, suctionpit). Solids other than sandmay be retained on the screen (e.g., lost circulationmaterial), and the presence of such solids should be noted.

Liquids and Solids Content A mud retort is used to determine the liquids and solids content of a drilling fluid.Mud is placed in a steel container and heated at high temperature until the liquid components have been
distilled off and vaporized (Figure 1.6). The vapors are passed through a condenser and collected in a graduated cylinder. The volume of liquids (water and oil) is then measured. Solids, both suspended and dissolved, are determined by volume as a difference between the mud in container and the distillate in graduated cylinder. Drilling fluid retorts are generally designed to distill 10-, 20-, or 50-ml sample volumes