A drilling fluid is not one product. It is a formulation, and every component in it is there to solve a specific problem: to hold back formation pressure, to carry cuttings to surface, to keep the wall of the hole standing, to stop fluid bleeding into the rock, and to do all of it without damaging the zone you are drilling for. This page explains what the main drilling fluid additives do, how to tell which one your problem calls for, and where the materials we supply fit into that picture. Every section links through to the detailed page for that product, so this is the place to start if you are building a mud programme or working out what to order.
What a drilling fluid has to do
Before any additive makes sense, it helps to be clear about the jobs the fluid is being asked to perform at the same time. Most of them pull against each other, which is why mud design is a balancing exercise rather than a recipe.
| Job | What happens if it fails | Controlled by |
|---|---|---|
| Balance formation pressure | A kick, and in the worst case a blowout | Mud weight — weighting material and dissolved salts |
| Carry cuttings to surface | Cuttings beds, packed-off annulus, stuck pipe | Viscosity and gel strength |
| Suspend solids when pumps stop | Barite sag, a heavy slug on start-up, lost well control | Gel strength |
| Keep the wall of the hole standing | Shale sloughing, washouts, a hole that will not log or case | Chemical inhibition and sealing additives |
| Limit fluid loss into the rock | Thick filter cake, differential sticking, formation damage | Filtration control polymers and sealing additives |
| Cool and lubricate the bit and string | Bit wear, high torque and drag, stuck pipe in deviated hole | Circulation rate and lubricity additives |
The tension between these is the whole problem. Raise the mud weight for pressure control and you increase the risk of fracturing the formation and losing returns. Raise viscosity to clean the hole and you raise pump pressure and reduce the rate of penetration. Every additive on this page is a lever on one of these jobs, and moving one lever moves the others.
The additive families, by function
Drilling fluid additives are easiest to understand grouped by the job they do rather than by what they are made of. This table is the map for the rest of the page.
| Function | What the additive does | Materials |
|---|---|---|
| Weighting | Adds mass to the fluid so hydrostatic pressure exceeds formation pressure | Barite, hematite, ilmenite |
| Viscosifying | Builds carrying capacity and gel strength so cuttings move and solids stay suspended | Bentonite, PAC HV, CMC HV, xanthan gum |
| Filtration control | Builds a thin, low-permeability filter cake and cuts fluid loss into the formation | PAC LV, CMC LV, gilsonite, starch |
| Shale inhibition | Stops reactive clays taking up water, swelling and falling into the hole | KCl, gilsonite, glycols, amines |
| Density by brine | Raises density through the water phase rather than with solids | Sodium chloride, calcium chloride, magnesium chloride |
| Alkalinity and pH | Holds pH where polymers work and corrosion is controlled, and treats out hardness | Caustic soda, soda ash, lime |
| Lost circulation | Bridges and seals openings so the fluid stays in the hole | Walnut shell, gilsonite, graphite, mica, fibre |
| Lubricity and sealing | Reduces torque and drag and plates the wellbore wall | Amorphous graphite, gilsonite, lubricants |
Start from the symptom
On a rig the problem rarely announces itself as a missing additive. It announces itself as a number moving in the wrong direction or a stand that will not come free. This table runs the other way round: from what you are seeing, to what is usually causing it, to what is normally added.
From what you see to what you add
| What you are seeing | Usual cause | Normally treated with |
|---|---|---|
| Returns dropping or lost entirely | Fractures, vugs or gravel taking fluid | Walnut shell with gilsonite, mica and fibre as a blended pill |
| Connection gas, flow checks positive | Mud weight below formation pressure | Barite, or brine density where solids are unwelcome |
| Cavings on the shakers, hole packing off | Reactive shale hydrating and sloughing | KCl for chemical inhibition plus gilsonite to seal microfractures |
| Thick filter cake, rising torque, pipe sticking | High fluid loss building cake across permeable zones | PAC LV or CMC LV, with gilsonite for the fine end |
| Cuttings not reaching surface, beds forming | Insufficient carrying capacity, especially in deviated hole | Bentonite and PAC HV to build viscosity and gels |
| Weight material settling in the hole or pits | Barite sag — gel strength too low for the solids load | Rheology correction with viscosifier; review barite grade and particle size |
| pH falling, polymers thinning, corrosion | Acid gas, cement contamination or make-up water hardness | Caustic soda, with soda ash for calcium |
| Hole enlarging through a salt section | Mud under-saturated with respect to the salt being drilled | Sodium chloride to saturation; magnesium chloride where carnallite or bischofite is present |
| High torque and drag in deviated hole | Metal-to-rock friction, poor filter cake quality | Amorphous graphite and sealing additives |
| Mud freezing or surface lines gelling in cold | Low ambient temperature on the surface system | Calcium chloride in the water phase to depress the freezing point |
One caution that applies across the whole table. If the interval is the producing zone and the plan is to restore permeability afterwards, bridging and sealing materials that cannot be removed will stay where you put them. Acid-soluble materials exist for exactly that case, and the choice has to be made before the pill is mixed rather than after.
Weighting: controlling density
Mud weight is the first line of well control. The hydrostatic column has to exceed formation pore pressure, with enough margin to be safe and not so much that the formation fractures and takes the fluid. The working window between those two limits narrows with depth, which is why heavy mud is a precision exercise rather than a matter of adding more.
Barite — barium sulphate — does almost all of this work worldwide. It is dense at around 4.2, chemically inert, soft enough not to damage pumps and bits, and cheap. API Specification 13A covers it in two grades: Section 7 at a minimum 4.20 specific gravity and Section 20 at 4.10. The difference matters more than it looks, because to reach the same mud weight with the lighter grade you add more material, and more solids means higher plastic viscosity and more wear.
The classic failure with weighting material is barite sag: particles settling out of suspension in a deviated hole while circulation is stopped, producing a light column above and a heavy slug below. It is a rheology problem rather than a barite problem, but it is the reason gel strength and weight material grading have to be considered together.
Viscosity and hole cleaning
A fluid that will not carry cuttings is not doing its job, however good it is at everything else. Carrying capacity depends on the fluid’s behaviour at low shear rates in the annulus, which is a different property from how it behaves through the bit nozzles, and the additives that build it are chosen for that reason.
Bentonite is the foundation of most water-based systems. Sodium bentonite hydrates and the clay platelets build a structure that gives the fluid gel strength when it is at rest and lets it thin when pumped. That shear-thinning behaviour is exactly what is wanted: viscous where cuttings need carrying, thin where it has to be pumped.
PAC HV and high-viscosity CMC are the polymer route to the same end. They build viscosity at much lower concentrations than clay and add very little solids, which keeps the system cleaner and reduces wear. In a salt-saturated system where bentonite cannot hydrate properly, a polymer is the only practical option.
Filtration control
Against any permeable formation the fluid loses its liquid phase into the rock and leaves solids behind as a filter cake. Some cake is wanted, because it is what seals the wall. Too much is the start of several expensive problems: a thick cake narrows the hole, increases the contact area for differential sticking, and the filtrate that has gone into the formation is what damages the pay.
PAC LV is the standard answer. It cuts fluid loss and builds a thin, tough, low-permeability cake while adding almost nothing to viscosity, which is why the low-viscosity grade exists as a separate product from PAC HV. CMC does a similar job and is often the more economical choice where the temperature and salinity suit it.
Gilsonite works on a different scale and by a different mechanism. It softens at downhole temperature and deforms into microfractures and pore throats that no polymer reaches, plating onto the wall and sealing what filtration polymers leave open. That is why the two are routinely used together rather than as alternatives, and why gilsonite appears again under lost circulation further down this page.
Shale inhibition and wellbore stability
Most hole problems are shale problems. Reactive clay takes up water from the fluid, swells, loses strength and falls into the hole. The cuttings come over the shakers soft and mushy or as hard angular cavings depending on the mechanism, and the consequences run from poor hole cleaning to a hole that will not log, case or cement.
There are two ways to deal with it and a good programme uses both. The chemical route is to change the water so the shale has less reason to take it up. Potassium chloride is the workhorse: the potassium ion fits the clay lattice and holds the layers together, which is why KCl inhibits where other salts at the same concentration do not. The physical route is to seal the shale so water cannot get in, and that is what gilsonite does, bridging and plugging the microfractures through which water invades.
A point worth keeping straight: KCl inhibits, it does not weight. Adding potassium chloride raises density slightly as any dissolved salt does, but density is a job for barite or for a deliberately designed brine. Treating KCl as a weighting material is a common and expensive confusion.
Brines: density without solids
There is a second way to make a fluid heavier, and in some situations it is the better one. Dissolving salt into the water phase raises density without adding a single particle of solid, which matters wherever solids would do harm: across a producing zone, in a completion or workover fluid, or in any system where plastic viscosity is already at its limit.
| Salt | Chosen for | Typical reason to reach for it |
|---|---|---|
| Sodium chloride | Cost, and saturation | Drilling a salt section without washing it out; the cheapest route to moderate density and mild inhibition |
| Calcium chloride | Higher density, freeze protection | Heavier clear brine than NaCl can reach, and protecting the surface system in cold climates |
| Magnesium chloride | Compatibility with magnesium-bearing formations | Carnallite and bischofite sections, which dissolve into a mud saturated only with sodium chloride |
| Potassium chloride | Inhibition first, density incidentally | Reactive shale; it is an inhibitor that happens to be a salt, not a weighting agent |
The trade-off with any brine is compatibility. Divalent salts such as calcium and magnesium chloride interfere with some polymers and flocculate clays, so a fluid designed around them is a different formulation rather than the same mud with salt added. Saturation with respect to the formation matters too: a mud that is saturated with sodium chloride will still dissolve a magnesium salt bed, which is the specific case magnesium chloride exists to solve.
Alkalinity, pH and contamination
pH is the quiet variable that everything else depends on. Cellulose polymers perform in a defined window and thin outside it. Corrosion of the string accelerates as pH falls. Acid gases entering from the formation drive it down, cement contamination drives it up, and hardness in the make-up water interferes with both the clays and the polymers.
Caustic soda is how the pH is held where it belongs, and it does a second job at the same time: it precipitates magnesium out of seawater or hard make-up water as magnesium hydroxide, which is how a system built on seawater is conditioned before anything else goes in. Soda ash handles calcium in the same way.
There is a neat circularity worth noticing. Magnesium is the contaminant caustic soda is used to remove from seawater make-up, and magnesium chloride is a deliberate additive when the formation itself contains magnesium salts. The same element is a problem in one context and the solution in another, which is why the alkalinity treatment has to be reviewed whenever the brine design changes.
Lost circulation
Losing returns is the single most expensive routine problem in drilling, and it escalates quickly. When the annulus is not full the hydrostatic column falls, and a falling column is how a loss turns into a kick. Before that there is stuck pipe, failed cement across the loss zone, and rig time spent circulating rather than drilling.
Lost circulation materials come in three shapes and they do different jobs, which is why a blend consistently outperforms any single material at the same total concentration:
Granular, to span the opening
Walnut shell is the standard: hard, resilient, insoluble in water and oil, and chemically inert. It jams in a fracture and takes the differential pressure across the bridge. Graded fine, medium and coarse, and matched to the opening width.
Sealing, to close what granules leave open
Gilsonite softens downhole and deforms into microfractures and pore throats that are far too small for any granule. It seals rather than spans, which is the complementary half of the job.
Flake and fibre, to complete the bridge
Mica and amorphous graphite lay across the face of the opening; cellulose fibre mats through the granular framework and stops the fines washing out once flow resumes.
A practical guideline for sizing the granular fraction: the median particle size should be at least a third of the opening it has to bridge. Below that the material passes straight through. That rule, run backwards, is how a grade is chosen from an estimated fracture width, and it is also why a single-grade pill underperforms — a real loss zone is never one width.
Water-based, oil-based and synthetic systems
Which additives apply depends on what the continuous phase is, and the choice of system is usually made on the formation and the environmental regime rather than on performance alone.
| System | Strengths | Where the additives differ |
|---|---|---|
| Water-based (WBM) | Cheap, simple to handle, straightforward to dispose of | Clay and cellulose chemistry dominates: bentonite, PAC, CMC, KCl for inhibition |
| Oil-based (OBM) | Excellent shale stability, lubricity and temperature tolerance | Water-soluble polymers do not apply; oil-dispersible additives and gilsonite take their place |
| Synthetic-based (SBM) | OBM performance with a better environmental profile | Similar additive logic to OBM; discharge rules drive the choice of materials |
Some materials cross all three. Barite weights any system. Walnut shell is insoluble in both water and oil, so the same product bridges in either. Gilsonite works in water-based, oil-based and synthetic systems alike, which is a large part of why it remains in use after decades.
How a water-based system is built up
Order of addition matters more than most people expect. Added in the wrong sequence, the same materials in the same quantities will give a fluid that will not perform, and the cause is rarely obvious afterwards.
| Step | What goes in | Why in this order |
|---|---|---|
| 1 | Make-up water, tested for hardness and chlorides | Everything downstream depends on what is already dissolved in it |
| 2 | Soda ash for calcium, caustic soda for pH and magnesium | Hardness must be treated out before clay or polymer goes in, or neither will hydrate properly |
| 3 | Bentonite, allowed to prehydrate | Clay needs time and clean water to develop yield; salt added first prevents it |
| 4 | Polymers — PAC HV, PAC LV, CMC | Added slowly through the hopper so they disperse rather than fish-eye |
| 5 | Salts — KCl, NaCl or the designed brine | After the clay has hydrated, because salt suppresses hydration |
| 6 | Barite to final weight | Last, once rheology is established, so gel strength can hold the solids in suspension |
| 7 | Loss control material as required | Carried as background treatment or mixed as a pill, depending on the interval |
Where gilsonite fits
Gilsonite is a naturally occurring solid hydrocarbon, and it has been in drilling fluids for decades because it does several jobs at once that would otherwise take several products. It is the material this company was built on, and it is worth understanding where it sits relative to everything above.
Fluid loss control
Softens at downhole temperature and seals the microfractures and pore throats that filtration polymers cannot reach, producing a thinner, tougher filter cake.
Shale stabilisation
Plates onto the wellbore wall and plugs the pathways water uses to invade reactive shale, working alongside chemical inhibition rather than instead of it.
Oil and water-based systems
Performs in both, which is unusual. Most additives belong to one phase; gilsonite moves between them, so the same material covers a whole programme.
Deepwater work
Used where discharge rules are strict and where the combination of sealing and stabilisation reduces the number of separate products that have to be shipped offshore.
What we supply, and how we work
Everything named on this page is part of our range. RAHA Gilsonite Co. supplies and exports gilsonite and the full range of drilling fluid additives — weighting material, viscosifiers, filtration control polymers, inhibition salts, brines, alkalinity control and loss circulation materials — by the container, worldwide.
One desk for the programme
A mud programme needs eight or ten materials. Buying them from eight suppliers means eight negotiations, eight shipments and eight sets of documents. Here it is one consignment, one invoice and one person to call when something needs answering.
Specifications published before you ask
Every product page on this site carries the analysis or the grading openly rather than behind an enquiry form, and every consignment ships with its own batch certificate against that specification.
Technical answers, not brochures
Ask how much salt saturates a 2,000 barrel water phase, which barite grade suits your mud weight, or what bridges a 4 mm fracture, and you get a worked answer rather than a price list.
Two loading ports
We load from Jebel Ali and from Mersin. On commodity chemicals freight often decides the delivered price, so working both routes means we can tell you which one wins for your destination.
Inspection welcomed
We arrange independent inspection and sampling at loading by SGS, Bureau Veritas, Intertek or the surveyor named in your contract, whenever you ask for it.
Consistent commercial terms
One full container minimum, FOB, CFR or CIF, loading from Jebel Ali or Mersin, 50 per cent by telegraphic transfer in advance with the balance agreed with the order. The same terms across the range.
If you are putting a programme together rather than buying a single item, send the well profile, the mud system and the intervals rather than a shopping list. It is usually possible to consolidate into fewer shipments and to flag where one material would do the work of two, and both of those change the number at the bottom more than a discount on any single line.
Frequently asked questions
Understanding the fluid
What are drilling fluid additives?
They are the materials blended into a drilling fluid to give it the properties the well requires: density to balance formation pressure, viscosity to carry cuttings, filtration control to limit fluid loss into the rock, chemical inhibition to keep shale stable, alkalinity control, and bridging materials to stop lost circulation. A working mud is typically eight to twelve materials, each addressing one of those jobs.
What is the difference between drilling mud and drilling fluid?
In practice they are used interchangeably. Drilling fluid is the broader and more formal term and covers air and foam systems as well as liquids; drilling mud usually implies a liquid system carrying solids. Nobody will misunderstand you either way.
Why do additives work against each other?
Because the jobs do. Raising mud weight for pressure control brings you closer to fracturing the formation and losing returns. Raising viscosity to clean the hole raises pump pressure and slows penetration. Adding solids for density raises plastic viscosity and wear. Mud design is the balance between those, which is why a formulation that works on one well is not simply transferable to another.
Choosing a material
Which additive raises mud weight?
Barite in almost every case, because it is dense, inert, soft on equipment and inexpensive. The alternative is to carry density in the water phase using a brine such as calcium chloride, which is the right route when solids would damage the producing zone or when plastic viscosity is already at its limit.
What is the difference between PAC LV and PAC HV?
The job each one does. PAC LV is for filtration control and is formulated to cut fluid loss while adding almost nothing to viscosity. PAC HV is for building viscosity and carrying capacity. They are the same chemistry at different molecular weights, and using one where the other is needed gives a fluid with the wrong property raised.
Does KCl make the mud heavier?
Only incidentally, as any dissolved salt does. Potassium chloride is an inhibitor: the potassium ion stabilises reactive clay so shale does not swell and slough. If you need density, that is a job for barite or a designed brine, and treating KCl as a weighting material is an expensive misunderstanding.
Polymers, clay and lost circulation
Which lost circulation material should I use?
A blend rather than one material. Walnut shell as the granular element to span the opening, gilsonite to seal what the granules leave open, and flake and fibre to complete the bridge. Size the granular fraction so its median particle is at least a third of the opening width, and remember that an acid-soluble material is the right choice across a zone you intend to clean up afterwards.
Do I need bentonite if I am using polymers?
Not necessarily. Polymer systems build viscosity at far lower concentrations and add almost no solids, which keeps the fluid cleaner. In a salt-saturated system bentonite cannot hydrate properly and a polymer is the only workable route. Clay remains the cheaper foundation in conventional water-based muds, so both approaches are in everyday use.
Compatibility and sequence
Does the order of addition matter?
Considerably. Hardness is treated out first, then clay is given time to prehydrate in clean water, then polymers, then salts, and weighting material last once the rheology is established. Adding salt before the bentonite has hydrated stops it developing yield, and the result is a fluid that will not perform for reasons that are not visible afterwards.
Can calcium and magnesium salts be used with any polymer?
No. Divalent salts flocculate clays and interfere with some polymers, so a fluid built around calcium chloride or magnesium chloride is a different formulation rather than a standard mud with salt added. The polymer selection and the alkalinity treatment both need reviewing when the brine changes.
Why does pH matter so much?
Because cellulose polymers perform within a defined window and thin outside it, and because corrosion accelerates as pH falls. Caustic soda holds it where it belongs and simultaneously precipitates magnesium out of seawater or hard make-up water, which is how a seawater system is conditioned before anything else is added.
Can the same additives be used in oil-based mud?
Some, not all. Water-soluble polymers do not function in an oil-based system and oil-dispersible equivalents take their place. Barite, walnut shell and gilsonite all work in water-based, oil-based and synthetic systems alike.
Ordering
Can all of these ship together?
Yes, and it is usually cheaper. A full mud programme consolidated into one consignment means one set of documents, one freight negotiation and one point of contact. Tell us the well profile and the intervals rather than sending a line-item list and we will work out how best to consolidate it.
What is the minimum order?
One full container, which can be made up of several products rather than one. Commercial terms are the same across the range: FOB, CFR or CIF, loading from Jebel Ali or Mersin, 50 per cent by telegraphic transfer in advance with the balance agreed with the order.
Do you publish specifications before an enquiry?
Yes. Each product page on this site carries the analysis or grading openly rather than behind a form, and every consignment ships with a batch certificate against that specification. Independent inspection at loading is arranged on request.
Build the programme from one desk
Every one of the drilling fluid additives described on this page is supplied and exported by RAHA Gilsonite Co. — gilsonite, barite, bentonite, the cellulose polymers, the inhibition salts and brines, caustic soda, graphite and walnut shell — with specifications published openly and a batch certificate on every shipment. Send the well profile, the mud system and the intervals, and you get a worked recommendation with the quotation rather than a price list.
Product pages: Barite · Bentonite · KCl · PAC LV · PAC HV · CMC · Caustic soda · Calcium chloride · Sodium chloride · Magnesium chloride · Walnut shell · Amorphous graphite · Gilsonite FLC · Gilsonite shale stabilisation · Gilsonite in deepwater · Water-based muds · Oil-based muds
