drilling mud pump calculations free sample

Rig pump output, normally in volume per stroke, of mud pumps on the rig is  one of important figures that we really need to know because we will use pump out put figures to calculate many parameters such as bottom up strokes,  wash out depth, tracking drilling fluid, etc. In this post, you will learn how to calculate pump out put for triplex pump and duplex pump in bothOilfield and Metric Unit.

Bourgoyne, A.J.T., Chenevert , M.E. & Millheim, K.K., 1986. SPE Textbook Series, Volume 2: Applied Drilling Engineering, Society of Petroleum Engineers.

Oil and Gas drilling process - Pupm output for Triplex and Duplex pumpsTriplex Pump Formula 1 PO, bbl/stk = 0.000243 x ( in) E.xample: Determine the pump output, bbl/stk, at 100% efficiency for a 7" by 12". triplex pump: PO @ 100%,= 0.000243 x 7 x12 PO @ 100% = 0.142884bbl/stk Adjust the pump output for 95% efficiency: Decimal equivalent = 95 + 100 = 0.95 PO @ 95% = 0.142884bbl/stk x 0.95 PO @ 95% = 0.13574bbl/stk Formula 2 PO, gpm = [3(D x 0.7854)S]0.00411 x SPM where D = liner diameter, in. S = stroke length, in. SPM = strokes per minute Determine the pump output, gpm, for a 7" by 12". triplex pump at 80 strokes per minute: PO, gpm = [3(7 x 0.7854) 1210.00411 x 80 PO, gpm = 1385.4456 x 0.00411 x 80 PO = 455.5 gpm

Example:Duplex Pump Formula 1 0.000324 x (liner diameter, in) x ( stroke lengh, in) = ________ bbl/stk -0.000162 x (rod diameter, in) x ( stroke lengh, in) = ________ bbl/stk Pump out put @ 100% eff = ________bbl/stk Example: Determine the output, bbl/stk, of a 5 1/2" by 14" duplex pump at 100% efficiency. Rod diameter = 2.0": 0.000324 x 5.5 x 14 = 0.137214bbl/stk -0.000162 x 2.0 x 14 = 0.009072bbl/stk Pump output @ 100% eff. = 0.128142bbl/stk Adjust pump output for 85% efficiency: Decimal equivalent = 85 100 = 0.85 PO@85%)= 0.128142bbl/stk x 0.85 PO@ 85% = 0.10892bbl/stk Formula 2

PO. bbl/stk = 0.000162 x S[2(D) - d] where S = stroke length, in. D = liner diameter, in. d = rod diameter, in. Example: Determine the output, bbl/stk, of a 5 1/2". by 14". duplex pump @ 100% efficiency. Rod diameter = 2.0in.: PO@100%=0.000162 x 14 x [ 2 (5.5) - 2 ] PO @ 100%)= 0.000162 x 14 x 56.5 PO@ 100%)= 0.128142bbl/stk Adjust pump output for 85% efficiency: PO@85%,= 0.128142bb/stkx 0.85 PO@8.5%= 0.10892bbl/stk Metric calculation Pump output, liter/min = pump output. liter/stk x pump speed, spm. S.I. units calculation Pump output, m/min = pump output, liter/stk x pump speed, spm. Mud Pumps Mud pumps drive the mud around the drilling system. Depending on liner size availability they can be set up to provide high pressure and low flow rate, or low pressure and high flow rate. Analysis of the application and running the Drill Bits hydraulics program will indicate which liners to recommend. Finding the specification of the mud pumps allows flow rate to be calculated from pump stroke rate, SPM. Information requiredo Pump manufacturer o Number of pumps o Liner size and gallons per revolution Weight As a drill bit cutting structure wears more weight will be required to achieve the same RoP in a homogenous formation. PDC wear flats, worn inserts and worn milled tooth teeth will make the bit drill less efficiently. Increase weight in increments of 2,000lbs approx. In general, weight should be applied before excessive rotary speed so that the cutting structure maintains a significant depth of cut to stabilise the bit and prevent whirl. If downhole weight measurements are available they can be used in combination with surface measurements to gain a more accurate representation of what is happening in the well bore.

Tri-Axial Casing Design is a completely new version of casing design covering both Bi-Axial and Tri-Axial calculations for bending, collapse and tension stress changes based in the maximum dog leg severity between Well Head and Casing Shoe. Including the option to look up the maximum DLS between any selected depths MD 1 to MD 2. The program picks the maximum DLS between the user inputs.

API rated burst strength is de-rated for temperatures from 10 to 600 F° (-12 to 316 C°) Drilling Condition – Gas/oil kick while drilling below the shoe with partial or total mud evacuation (user selects evac percent), with shut in pressurized column of gas/oil to surface and old mud weight gradient behind casing. The old MW that was behind the casing when it was cemented is used for annulus hydrostatic burst calculations and the present MW is used for internal hydrostatic calculations. The user inputs the gas/oil gradient that most closely fits their design for internal pressure gradient.

Drilling burst loads are calculated assuming a shut in gas/oil kick with Leak off EMW pressure at the shoe and a casing evacuation percent chosen by the user (typically 10 – 40 %).

Production burst loads are calculated assuming a full shut in column of pressured gas/oil (i.e. 100% mud evacuation), with Leakoff EMW pressure at the shoe and a column of salt water behind the casing. .

Drilling collapse loads are calculated assuming the casing has been partially or fully evacuated of mud (resulting from lost circulation, or a blowout), while drilling below the shoe, with a non-pressured column of gas/oil to the surface (i.e. atmospheric pressure at the surface) and a full column of old MW behind the casing. The user inputs the gas/oil gradient that most closely fits their design for internal pressure gradient.

. Production collapse loads are calculated assuming 100% mud evacuation with an un-pressured column of gas/oil to the surface. The old MW that was behind the casing when it was cemented is used for annulus hydrostatic collapse calculations. The user inputs the gas/oil gradient that most closely fits their design for internal pressure gradient.

Cementing Collapse loads are calculated with applicable hydrostatic columns of mud and cement slurries outside the casing and displacement fluid column inside the casing. The small hydrostatic difference of the cement in the shoe joints is ignored and displacement fluid is assumed to the shoe TVD. Cementing collapse is typically a concern with big OD conductors and surface casings.

Tensile Design API rated tensile strengths (body and joint), are de-rated for temps 10 to 600 F (-12 to 316 C). . Drilling and Production Casings are calculated with the same assumptions.

Tensile analysis considers the total hanging weight of the casing as it is being run in the hole. The user selects Vertical or Directional tensile analysis to calculate tensile loads assuming buoyant weight of steel in a mud filled hole. . Buoyancy factor = (65.4-MW)/65.4

Tri-Axial Casing Design includes a combination of csg and Liner installation, the new version of Casing Design now includes liner overlap calculations

Many groundwater professionals prefer using charts and tables to determine these values, and those tabulated references are available in the appendices of many textbooks and in handbooks from cement or drilling fluid suppliers.

This approach works well but relying on a printed reference is not without the risk since the wrong value can still be selected from the fine print of a reference table, or the reference document can be damaged or lost (e.g., dropped in the mud pit) altogether.

As we consider the various calculations that enable us to determine the values of length, weight, pressure, volume, flow velocity, etc., we should remain mindful of the units of measure we’re dealing with. The groundwater industry uses units of measure that are somewhat intermingled with other units from associated disciplines such as engineering, surface water hydrology, and the oil and gas drilling industry.

The intermediate casing can be sealed using the pressure grouting technique (Figure 3) to pump cement slurry down through the drill pipe and out to the annulus through a float shoe (a drillable check valve connected to the base of the casing). The inside of the intermediate casing is kept full of water during the cement placement to equilibrate hydraulic pressures inside and outside the casing. After the intermediate casing is sealed with the pressure grouted cement, the float shoe can be drilled out and the borehole advanced for installation of the screen and filter pack in the lower part of the well.

If you apply the weight calculations for a 400-foot-long steel casing with a 16-inch diameter and a 5/16-inch wall thickness, which is filled with water, you’ll see that the downward force in this example is only 52,982 pounds. Thus, the casing in this example will float. The lesson from this counterintuitive scenario is that a casing can actually float. (I’ve seen it happen, and trust me, you don’t want to).

For heavier-walled casing materials or deeper wells, there are situations where the “string weight” of the casing and screen may exceed the safe hang weight of the casing string, or even exceed the mast capacity of the drilling rig. A good rule-of-thumb is to maintain a rig mast capacity that is no less than 1.5 times the string weight.

There are several calculations that are commonly applied by drilling fluid engineers (mud engineers) to determine the time period required for the fluid to move from one location in the borehole to another. Some of the more common equations are described below.

The uphole velocity calculation provides a determination of the speed at which the drilling mud will flow as it moves up the borehole. For direct air rotary or reverse circulation drilling methods, the uphole velocity is high, so this calculation is generally applicable only for the direct mud-rotary drilling method. The formula for uphole velocity is:

Notice the uphole velocity formula is similar to the annular volume formula in that both those calculations use the factor (D2 – d2) to address the cross-sectional area of the annulus. However, the constants in these two formulas are different (0.005454 versus 24.51), which can be confusing. Keep in mind, however, that the constants primarily just provide unit conversions.

Thebottoms-up time calculation enables us to determine the time period for the drilling fluid (and the cuttings it is carrying) to travel from the drill bit up to the land surface. This is illustrated in Figure 6(A).

We can calculate the bottoms-up time by using the uphole velocity formula with the borehole depth and drilling mud flow rate plugged in, but that flow rate is being generated by the mud pump, and positive displacement mud pumps (duplex or triplex) are almost never equipped with a flow meter. To determine the flow coming from the mud pump, we can use the formulas:

Remember the strokes are counted in both the forward and backward directions on a duplex pump, but only in the forward direction on a triplex pump. Drillers often have reference charts that provide oilfield barrels per stroke (bbl/stroke), which can be converted to gpm by timing the strokes per minute and converting barrels to gallons (1 barrel = 42 gallons).

The round-trip time enables us to see the result of drilling fluid additives, as indicated by the return flow of fluids at the land surface, as is illustrated in Figure 6(B). The round-trip time calculation is the same as bottoms-up time, but with the travel time of fluid to displace the drill pipe added in.

A specified volume of drilling fluids (called a pill) can be circulated to a particular depth interval within the borehole (called spotting), so that the additives in the pill of drilling mud can address the borehole problem at a particular depth of the borehole. This is shown in Figure 6(C).

The calculation for time required to spot a pill of drillingfluid involves determining the pumping time (at the calculated flow rate) required to displace the fluid so that the drilling mud additives are located adjacent to the problematic interval. This approach is used by mud engineers to address problems such as lost circulation or stuck drill pipe.

The formulas and calculations provided in this column and elsewhere provide important tools for us to quantify the variables we need for water well design and construction. However, it is important to remember that “doing the math” is not a replacement for applying professional knowledge and consideration to determine whether the mathematical result makes common sense.

MUDSheet app covers the most essential calculation and data in mud engineering. Designed for mud engineers and drilling engineers, MUDSheet is an app which contains 22 most commonly used calculations, ranging from pipe capacity, pump output to mud additives. We, engineers, are often overwhelmed by the information scattered around in various media forms. Now, the most essential information from engineering handbooks, SPE textbooks, IADC manuals, has been distilled into MUDSheet, a must-have application for every mud engineer and technician to get the job done accurately and efficiently.

When choosing a size and type of mud pump for your drilling project, there are several factors to consider. These would include not only cost and size of pump that best fits your drilling rig, but also the diameter, depth and hole conditions you are drilling through. I know that this sounds like a lot to consider, but if you are set up the right way before the job starts, you will thank me later.

Recommended practice is to maintain a minimum of 100 to 150 feet per minute of uphole velocity for drill cuttings. Larger diameter wells for irrigation, agriculture or municipalities may violate this rule, because it may not be economically feasible to pump this much mud for the job. Uphole velocity is determined by the flow rate of the mud system, diameter of the borehole and the diameter of the drill pipe. There are many tools, including handbooks, rule of thumb, slide rule calculators and now apps on your handheld device, to calculate velocity. It is always good to remember the time it takes to get the cuttings off the bottom of the well. If you are drilling at 200 feet, then a 100-foot-per-minute velocity means that it would take two minutes to get the cuttings out of the hole. This is always a good reminder of what you are drilling through and how long ago it was that you drilled it. Ground conditions and rock formations are ever changing as you go deeper. Wouldn’t it be nice if they all remained the same?

Centrifugal-style mud pumps are very popular in our industry due to their size and weight, as well as flow rate capacity for an affordable price. There are many models and brands out there, and most of them are very good value. How does a centrifugal mud pump work? The rotation of the impeller accelerates the fluid into the volute or diffuser chamber. The added energy from the acceleration increases the velocity and pressure of the fluid. These pumps are known to be very inefficient. This means that it takes more energy to increase the flow and pressure of the fluid when compared to a piston-style pump. However, you have a significant advantage in flow rates from a centrifugal pump versus a piston pump. If you are drilling deeper wells with heavier cuttings, you will be forced at some point to use a piston-style mud pump. They have much higher efficiencies in transferring the input energy into flow and pressure, therefore resulting in much higher pressure capabilities.

Piston-style mud pumps utilize a piston or plunger that travels back and forth in a chamber known as a cylinder. These pumps are also called “positive displacement” pumps because they literally push the fluid forward. This fluid builds up pressure and forces a spring-loaded valve to open and allow the fluid to escape into the discharge piping of the pump and then down the borehole. Since the expansion process is much smaller (almost insignificant) compared to a centrifugal pump, there is much lower energy loss. Plunger-style pumps can develop upwards of 15,000 psi for well treatments and hydraulic fracturing. Centrifugal pumps, in comparison, usually operate below 300 psi. If you are comparing most drilling pumps, centrifugal pumps operate from 60 to 125 psi and piston pumps operate around 150 to 300 psi. There are many exceptions and special applications for drilling, but these numbers should cover 80 percent of all equipment operating out there.

The restriction of putting a piston-style mud pump onto drilling rigs has always been the physical size and weight to provide adequate flow and pressure to your drilling fluid. Because of this, the industry needed a new solution to this age-old issue.

As the senior design engineer for Ingersoll-Rand’s Deephole Drilling Business Unit, I had the distinct pleasure of working with him and incorporating his Centerline Mud Pump into our drilling rig platforms.

In the late ’90s — and perhaps even earlier —  Ingersoll-Rand had tried several times to develop a hydraulic-driven mud pump that would last an acceptable life- and duty-cycle for a well drilling contractor. With all of our resources and design wisdom, we were unable to solve this problem. Not only did Miller provide a solution, thus saving the size and weight of a typical gear-driven mud pump, he also provided a new offering — a mono-cylinder mud pump. This double-acting piston pump provided as much mud flow and pressure as a standard 5 X 6 duplex pump with incredible size and weight savings.

The true innovation was providing the well driller a solution for their mud pump requirements that was the right size and weight to integrate into both existing and new drilling rigs. Regardless of drill rig manufacturer and hydraulic system design, Centerline has provided a mud pump integration on hundreds of customer’s drilling rigs. Both mono-cylinder and duplex-cylinder pumps can fit nicely on the deck, across the frame or even be configured for under-deck mounting. This would not be possible with conventional mud pump designs.

The second generation design for the Centerline Mud Pump is expected later this year, and I believe it will be a true game changer for this industry. It also will open up the application to many other industries that require a heavier-duty cycle for a piston pump application.

In geotechnical engineering, drilling fluid, also called drilling mud, is used to aid the drilling of boreholes into the earth. Often used while drilling oil and natural gas wells and on exploration drilling rigs, drilling fluids are also used for much simpler boreholes, such as water wells. One of the functions of drilling mud is to carry cuttings out of the hole.

The three main categories of drilling fluids are water-based muds (WBs), which can be dispersed and non-dispersed; non-aqueous muds, usually called oil-based muds (OBs); and gaseous drilling fluid, in which a wide range of gases can be used. Along with their formatives, these are used along with appropriate polymer and clay additives for drilling various oil and gas formations.

The main functions of drilling fluids include providing hydrostatic pressure to prevent formation fluids from entering into the well bore, keeping the drill bit cool and clean during drilling, carrying out drill cuttings, and suspending the drill cuttings while drilling is paused and when the drilling assembly is brought in and out of the hole. The drilling fluid used for a particular job is selected to avoid formation damage and to limit corrosion.

Many types of drilling fluids are used on a day-to-day basis. Some wells require different types to be used in different parts of the hole, or that some types be used in combination with others. The various types of fluid generally fall into broad categories:

Water-based mud (WBM): Most water-based mud systems begin with water, then clays and other chemicals are added to create a homogeneous blend with viscosity between chocolate milk and a malt. The clay is usually a combination of native clays that are suspended in the fluid while drilling, or specific types of clay processed and sold as additives for the WBM system. The most common type is bentonite, called "gel" in the oilfield. The name likely refers to the fluid viscosity as very thin and free-flowing (like chocolate milk) while being pumped, but when pumping is stopped, the static fluid congeals to a "gel" that resists flow. When adequate pumping force is applied to "break the gel," flow resumes and the fluid returns to its free-flowing state. Many other chemicals (e.g. potassium formate) are added to a WBM system to achieve desired effects, including: viscosity control, shale stability, enhance drilling rate of penetration, and cooling and lubricating of equipment.

Oil-based mud (OBM): Oil-based mud has a petroleum based fluid such as diesel fuel. Oil-based muds are used for increased lubricity, enhanced shale inhibition, and greater cleaning abilities with less viscosity. Oil-based muds also withstand greater heat without breaking down. The use of oil-based muds has special considerations of cost, environmental concerns such as disposal of cuttings in an appropriate place, and the exploratory disadvantages of using oil-based mud, especially in wildcat wells. Using an oil-based mud interferes with the geochemical analysis of cuttings and cores and with the determination of API gravity because the base fluid cannot be distinguished from oil that is returned from the formation.

Synthetic-based fluid (SBM) (Otherwise known as Low Toxicity Oil Based Mud or LTOBM): Synthetic-based fluid is a mud in which the base fluid is a synthetic oil. This is most often used on offshore rigs because it has the properties of an oil-based mud, but the toxicity of the fluid fumes are much less. This is important when the drilling crew works with the fluid in an enclosed space such as an offshore drilling rig. Synthetic-based fluid poses the same environmental and analysis problems as oil-based fluid.

On a drilling rig, mud is pumped from the casing, where it emerges from the top. Cuttings are then filtered out with either a shale shaker or the newer shale conveyor technology, and the mud returns to the mud pits. The mud pits allow the drilled "fines" to settle and the mud to be treated by adding chemicals and other substances.

The returning mud may contain natural gases or other flammable materials which will collect in and around the shale shaker / conveyor area or in other work areas. Because of the risk of a fire or an explosion if they ignite, special monitoring sensors and explosion-proof certified equipment is commonly installed, and workers are trained in safety precautions. The mud is then pumped back down the hole and further re-circulated. After testing, the mud is treated periodically in the mud pits to ensure it has desired properties that optimize and improve drilling efficiency and borehole stability.

Drilling fluid carries the rock excavated by the drill bit up to the surface. Its ability to do so depends on cutting size, shape, and density, and speed of fluid traveling up the well (annular velocity). These considerations are analogous to the ability of a stream to carry sediment. Large sand grains in a slow-moving stream settle to the stream bed, while small sand grains in a fast-moving stream are carried along with the water. The mud viscosity is an important property, as cuttings will settle to the bottom of the well if the viscosity is too low.

Most drilling muds are thixotropic (viscosity increases when static). This characteristic keeps the cuttings suspended when the mud is not flowing during, for example, maintenance.

High density fluids may clean holes adequately even with lower annular velocities (by increasing the buoyancy force acting on cuttings) but may have a negative impact if mud weight exceeds that needed to balance the pressure of surrounding rock (formation pressure), so mud weight is not usually increased for hole cleaning.

For effective solids controls, drill solids must be removed from mud on the 1st circulation from the well. If re-circulated, cuttings break into smaller pieces and are more difficult to remove.

If formation pressure increases, mud density should be increased to balance pressure and keep the wellbore stable. The most common weighting material is baryte. Unbalanced formation pressure will cause an unexpected influx (also known as a kick) of formation fluids into the wellbore possibly leading to a blowout from pressurized formation fluid.

Hydrostatic pressure = density of drilling fluid * true vertical depth * acceleration of gravity. If hydrostatic pressure is greater than or equal to formation pressure, formation fluid will not flow into the wellbore.

In practice, mud density should be limited to the minimum necessary for well control and wellbore stability. If too great it may fracture the formation.

Mud column pressure must exceed formation pressure, in this condition mud filtrate invades the formation, and a filter cake of mud is deposited on the wellbore wall.

Depending on the mud system in use, a number of additives can improve the filter cake (e.g. bentonite, natural & synthetic polymer, asphalt and gilsonite).

Chemical composition and mud properties must combine to provide a stable wellbore. Weight of the mud must be within the necessary range to balance the mechanical forces.

In shales, mud weight is usually sufficient to balance formation stress, as these wells are usually stable. With water base mud, chemical differences can cause interactions between mud & shale that lead to softening of the native rock. Highly fractured, dry, brittle shales can be extremely unstable (leading to mechanical problems).

Various chemical inhibitors can control mud / shale interactions (calcium, potassium, salt, polymers, asphalt, glycols and oil – best for water sensitive formations)

To add inhibition, emulsified brine phase (calcium chloride) drilling fluids are used to reduce water activity and creates osmotic forces to prevent adsorption of water by Shales.

Lubrication based on the coefficient of friction.("Coefficient of friction" is how much friction on side of wellbore and collar size or drill pipe size to pull stuck pipe) Oil- and synthetic-based mud generally lubricate better than water-based mud (but the latter can be improved by the addition of lubricants).

Drilling fluids also support portion of drill-string or casing through buoyancy. Suspend in drilling fluid, buoyed by force equal to weight (or density) of mud, so reducing hook load at derrick.

Hydraulic energy provides power to mud motor for bit rotation and for MWD (measurement while drilling) and LWD (logging while drilling) tools. Hydraulic programs base on bit nozzles sizing for available mud pump horsepower to optimize jet impact at bottom well.

Mud loggers examine cuttings for mineral composition, visual sign of hydrocarbons and recorded mud logs of lithology, ROP, gas detection or geological parameters.

Mud should have thin, slick filter cake, with minimal solids in filter cake, wellbore with minimal cuttings, caving or bridges will prevent a good casing run to bottom. Circulate well bore until clean.

Mud low viscosity, mud parameters should be tolerant of formations being drilled, and drilling fluid composition, turbulent flow - low viscosity high pump rate, laminar flow - high viscosity, high pump rate.

Water based drilling fluid has very little toxicity, made from water, bentonite and baryte, all clay from mining operations, usually found in Wyoming and in Lunde, Telemark.

There are specific chemicals that can be used in water based drilling fluids that alone can be corrosive and toxic, such as hydrochloric acid. However,

Caustic (sodium hydroxide), anhydrous lime, soda ash, bentonite, baryte and polymers are the most common chemicals used in water based drilling fluids.

Water-based drilling mud most commonly consists of bentonite clay (gel) with additives such as barium sulfate (baryte), calcium carbonate (chalk) or hematite. Various thickeners are used to influence the viscosity of the fluid, e.g. xanthan gum, guar gum, glycol, carboxymethylcellulose, polyanionic cellulose (PAC), or starch. In turn, deflocculants are used to reduce viscosity of clay-based muds; anionic polyelectrolytes (e.g. acrylates, polyphosphates, lignosulfonates (Lig) or tannic acid derivates such as Quebracho) are frequently used. Red mud was the name for a Quebracho-based mixture, named after the color of the red tannic acid salts; it was commonly used in the 1940s to 1950s, then was made obsolete when lignosulfonates became available. Other components are added to provide various specific functional characteristics as listed above. Some other common additives include lubricants, shale inhibitors, fluid loss additives (to control loss of drilling fluids into permeable formations). A weighting agent such as baryte is added to increase the overall density of the drilling fluid so that sufficient bottom hole pressure can be maintained thereby preventing an unwanted (and often dangerous) influx of formation fluids

Freshwater mud: Low pH mud (7.0–9.5) that includes spud, bentonite, natural, phosphate treated muds, organic mud and organic colloid treated mud. high pH mud example alkaline tannate treated muds are above 9.5 in pH.

Water based drilling mud that represses hydration and dispersion of clay – There are 4 types: high pH lime muds, low pH gypsum, seawater and saturated salt water muds.

Low solids mud: These muds contain less than 3–6% solids by volume and weight less than 9.5 lbs/gal. Most muds of this type are water-based with varying quantities of bentonite and a polymer.

Oil based mud: Oil based muds contain oil as the continuous phase and water as a contaminant, and not an element in the design of the mud. They typically contain less than 5% (by volume) water. Oil-based muds are usually a mixture of diesel fuel and asphalt, however can be based on produced crude oil and mud

"Mud engineer" is the name given to an oil field service company individual who is charged with maintaining a drilling fluid or completion fluid system on an oil and/or gas drilling rig.mud engineer, or more properly drilling fluids engineer, is critical to the entire drilling operation because even small problems with mud can stop the whole operations on rig. The internationally accepted shift pattern at off-shore drilling operations is personnel (including mud engineers) work on a 28-day shift pattern, where they work for 28 continuous days and rest the following 28 days. In Europe this is more commonly a 21-day shift pattern.

In offshore drilling, with new technology and high total day costs, wells are being drilled extremely fast. Having two mud engineers makes economic sense to prevent down time due to drilling fluid difficulties. Two mud engineers also reduce insurance costs to oil companies for environmental damage that oil companies are responsible for during drilling and production. A senior mud engineer typically works in the day, and a junior mud engineer at night.

The cost of the drilling fluid is typically about 10% (may vary greatly) of the total cost of drilling a well, and demands competent mud engineers. Large cost savings result when the mud engineer and fluid performs adequately.

The compliance engineer is the most common name for a relatively new position in the oil field, emerging around 2002 due to new environmental regulations on synthetic mud in the United States. Previously, synthetic mud was regulated the same as water-based mud and could be disposed of in offshore waters due to low toxicity to marine organisms. New regulations restrict the amount of synthetic oil that can be discharged. These new regulations created a significant burden in the form of tests needed to determine the "ROC" or retention on cuttings, sampling to determine the percentage of crude oil in the drilling mud, and extensive documentation. No type of oil/synthetic based mud (or drilled cuttings contaminated with OBM/SBM) may be dumped in the North Sea. Contaminated mud must either be shipped back to shore in skips or processed on the rigs.

Clark, Peter E. (1995-01-01). "Drilling Mud Rheology and the API Recommended Measurements". SPE Production Operations Symposium. Society of Petroleum Engineers. doi:10.2118/29543-MS. ISBN 9781555634483.