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The country’s energy is mainly encompassed by the drilled and extracted oil and gas reserves and other natural resources, consequently this is the main source of Nigeria’s economy. Drilling is an essential piece of oil and gas sector claiming without drilling, there would be no entrance to oil and gas which is for the most part underneath the earth crust. Drilling is a procedure of making an opening in the earths’ surface mostly to create access to the accessible asset underneath the earth. Drilling ought to be done safely and must not have negative effect on the environment (Drilling Fluids Manual). A drilling fluid is a circulating fluid utilized while drilling for a few purposes. Some of these capacities could include cuttings transport, particle suspension, subsurface pressure control, wellbore stabilization, bit lubrication, corrosion control, prevention of formation damage, transmission of hydraulic horse power to the bit, sealing of permeable formations, facilitation of formation data collection from drilled cuttings, cores and electrical logs. Salt is included as one of the parts of an oil base drilling fluid for a few reasons. It is added to the oil base fluid to increase the density of the fluid, to maintain well stability while drilling water sensitive formations like shale, to diminish the mud resistivity of the fluid, and to respond with the emulsifier for better emulsion (Ayoade, 2013).
API Barite offers an edge, for example, inert with other drilling fluid chemical additives, and high specific gravity (SG = 4.2), resulting in less required volume for a higher desired fluid density. Having a high SG can likewise be an inconvenience when the settling of particles is dangerous. CaCO3 is a mineral that is utilized as a bridging agent and additionally weighting material in drilling and completion fluids. CaCO3 has a SG of 2.71 – 2.83. CaCO3 is roughly 98% solvent in hydrochloric acid solution, which is normal inorganic acid utilized as a part of formation pore stimulation (Drilling Fluids Manual). During a drilling operation, it is normal for the drilling fluid to end up distinctly contaminated. These contaminants often change the properties of the drilling fluid and adversely influence the drilling operation. Oftentimes conformities must be made to the drilling fluid on location. The results of such contamination could be an adjustment in pH of the drilling fluid. This experimental review will investigate how pH could influence the sag tendency of the drilling fluid. The ability of a drilling fluid to hold particles in suspension is vital. The failure of a drilling fluid to suspend weighting materials has prompted to the issue known as barite sag. Barite sag is the dynamic and static settling of weighting materials, followed by downward slumping of the fluidized beds that shape on the low side of the wellbore. The formation of these high-density beds and their subsequent recirculation can prompt to extreme operational problems, including well control issues, lost circulation, borehole instability and stuck pipe.
The major types of drilling fluids are
Water based drilling fluid (WBFs)
Pneumatic based drilling fluid (PBFs)
Oil based drilling fluid (OBFs)
Figure 1.0: Classification of Drilling Fluids (Drilling Fluids Manual).
Oil-based mud is a kind of drilling fluid which is mostly used in drilling. Oil-based fluids (OBFs) in use today are formulated with diesel, mineral oil or paraffin. The olefins and paraffin are often referred to as “synthetics” although some are derived from distillation of crude oil and some are chemically synthesised from smaller molecules. The electrical stability of the water phase or internal brine is monitored to help ensure that the strength of the emulsion is maintained at or near a predetermined value. The emulsion should be stable enough to incorporate additional water volume if a downhole water flow is encountered (Petrowiki, 2015).
Water-based fluids (WBFs) are the most widely used systems and are considered less expensive than oil-based fluids (OBFs) or synthetic-based fluids (SBFs). The SBFs and OBFs also called invert-emulsion systems have a synthetic base fluid or oil as the external (or continuous) phase, and brine as the internal phase. Invert-emulsion systems are costlier per unit than most water-based fluids, so they are mostly selected when well conditions call for reliable shale inhibition and/or excellent lubricity. Water based systems and invert-emulsion systems can be designed to tolerate relatively high downhole temperatures (Petrowiki, 2015).
Compressed air or gas is pumped either down the drill string. Pneumatic (air/gas based) fluids are used for drilling depleted zones or areas where abnormally low formation pressures may be encountered. An advantage of pneumatic drilling fluids over liquid muds systems can be seen in increased penetration rates. Cuttings are literally blown of the cutting surface ahead of the bit because of the considerable pressure differential. The high-pressure differential also allows formation fluids from permeable zones to flow into the wellbore. Air/gas drilling fluids are ineffective in areas where large volumes of formation fluids are encountered. A large influx of formation fluids requires converting the pneumatic fluid system into a liquid-based system. As a result, the chances of lost circulation and damaging a productive zone are greatly increased. Water is added to increase viscosity, flush the hole, provide more cooling and to control dust. Another consideration when selecting pneumatic fluids is well depth. They are not recommended for wells below about 10,000 feet deep because of the volume of air required to lift cuttings from the bottom of the hole can become greater than the surface equipment can deliver. (Drilling Fluids Manual)
Drilling engineers mostly select specific drilling fluid with the most favourable properties for the operation. Most drilling fluid functions are mainly controlled by its rheological properties.
A drilling fluid expert or “Mud Engineer” is mostly on site to maintain and revaluate these properties during drilling (Annudeep, 2012). The most important factors that are governing selection of drilling fluids are;
Type of formation to be drilled
Temperature ranges
Strength; permeability and pore fluids pressure exhibited by the formation.
While in addition to the listed above, selection of drilling fluid can be informed through consideration of other factors such as environmental impact, production concerns, safety and logistics, the most important factor that governs the selection of drilling fluid is “overall well cost” (Annudeep, 2012).
Oil based muds: are comparable in composition to water-based with the special case that the continuous phase is oil. In an invert emulsion mud, water may make-up a high percentage of the volume, yet oil is still the continuous phase
center14097000 Figure 1.1: Typical composition of an oil-based mud (Effendi, 2015)

A well formulated drilling fluid performs essential functions when used during transportation of cuttings to the surface, prevention of well-control issues and wellbore stability, minimizing formation damage, cooling and lubrication of the drill string and providing information about the down hole (Petrowiki, 2015).
1. Transport cuttings to surface
Drilled cutting transportation to the surface is a major capacity of drilling fluid. For this to be accurate, the fluid must have adequate suspension properties to ensure that cuttings and economically included solids, example, barite, doesn’t settle. The fluid must have the substance properties to anticipate or minimize scattering of drilled solids, so that these can be evacuated productively at the surface amid operation. Otherwise, these solids can breakdown into ultrafine particles that has likelihood of harming the producing zone, and obstruct drilling efficiency (Petrowiki, 2015).
2. Prevent well-control issues
Drilling fluid column in the well applies hydrostatic pressure in the wellbore. Under normal drilling conditions, the pressure ought to adjust or surpass the natural formation pressure to avoid influx of gas or other formation fluids. As the formation pressure builds up, the density of the drilling mud is expanded to keep a safe margin and prevent from “kicks” or “blow out.” Be that as it may, if the density of the fluid turns out to be too heavy, a break could happen in the formation. On the off chance that mud is lost in the resultant fractures then a lessening of hydrostatic pressure happens. The pressure reduction can likewise prompt an influx from a pressured formation. Hence, keeping up the suitable fluid density for the wellbore pressure regime is critical to safety and wellbore stability (Petrowiki, 2015).

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3. Preserve wellbore stability
Maintaining the drilling fluid density contains formation pressure, as well as helps keeps the hole from collapsing and the shale from destabilizing. The wellbore ought to be free from obstruction and tight spots, so that the drill string can be moved freely during tripping. After a hole section has been drilled to the planed depth, the wellbore ought to stay stable under static conditions while the casing is run to the base, and cemented (Petrowiki, 2015).
4. Minimize formation damage
Drilling operations uncovered the producing formation to the drilling mud and any solids and chemicals contained in that fluid. Some invasion of fluid filtrate or fine solids into the formation is unavoidable. Be that as it may, this intrusion, and the potential for harm to the formation, can be minimized with careful fluid design that depends on testing performed with cored samples of the formation of interest. Formation damage likewise can be reduced by expert management of downhole hydraulics utilizing exact modelling software, and by the choice of an extraordinarily outlined “drill-in” fluid, for example, such as the systems that commonly are executed while drilling horizontal wells (Petrowiki, 2015).
5. Cool and lubricate the drill string
The drill bit and drill string turns at moderately high revolutions per minute (rev/min) all or part of the time during genuine drilling operations. Course of drilling fluid through the drill string and up the wellbore annular space lessens grinding and cool the drill string. The drilling fluid additionally gives a high level of lubricity to help the development of the drill pipe and base gap get together (BHA). Oil-based fluids and engineered based fluids offer a high level of lubricity, thus, are the favoured fluid sorts for high-point directional wells. Some water based polymer frameworks additionally give lubricity drawing nearer that of the oil-and manufactured based frameworks (Petrowiki, 2015).

6.Provide information about the wellbore
Since drilling fluid is in consistent contact with the wellbore, it uncovers considerable data about the developments being drilled, and serves as a channel for much information gathered downhole by apparatuses situated on the drill string and through wireline-logging operations performed when the drill string is out of the opening. The drilling fluid’s capacity to protect the cuttings as they go up the annulus specifically influences the nature of investigation that can be performed on the cuttings. These cuttings serve as an essential marker of the physical and compound state of the drilling fluid. An advanced drilling fluid framework that creates a stable, in-gage wellbore can improve the nature of the information transmitted by downhole estimation and logging devices and additionally by wireline devices (Petrowiki, 2015).
7. Minimize risk to personnel, the environment, and drilling equipment
Drilling fluids require day by day testing, and nonstop observing by uniquely prepared staff. The security risks connected with treatment of a fluid are plainly shown in the fluid’s documentation. Drilling fluids likewise are nearly examined by overall administrative organizations to guarantee that the details being used conform to controls set up to ensure both characteristic and human groups where drilling happens. At the rigsite, the hardware used to pump or process fluid is checked continually for indications of wear from scraped area or substance consumption. The upper opening segments commonly are drilled with low-viscosity water-based fluids (WBFs). Contingent upon arrangement sorts, downhole temperatures, directional-drilling arrangements, and different variables, the administrator may change to an OBF or SBF at a foreordained point in the drilling procedure. Elite WBFs additionally are accessible to meet an assortment of drilling difficulties (Petrowiki, 2015).

Calcium carbonate is a substance compound with the formula CaCO3. It is a typical substance found in rocks as the minerals, calcite and aragonite (most outstandingly as limestone, which contains both of those minerals) and is the principle part of pearls and the shells of marine life forms, snails, and eggs. Calcium carbonate is the active ingredient in agricultural lime and is made when calcium particles in hard water reacts with carbonate particles to make limescale. It is medicinally utilized as a calcium supplement or as an antacid; however unreasonable consumption can be dangerous (Wikipedia, 2017).
Barite (BaSO4) is a mineral which consist of barium and sulfate. The barite group consists of barite, anhydrite, anglesite and Celestine. Barite generally is a white or colourless, and is the major source of barium. Barite has a SG of 4.3-5. Barite occurs in a large number of depositional environments, and is deposited through a large number of processes including biogenic, hydrothermal, and evaporation, among others, 77% of barite worldwide is used as a weighting agent for drilling fluids in oil and gas exploration to suppress high formation pressures and prevent blowouts (Hanor, 2000).
Barite sag is drilling mud problem and it occurs when weighting material separates from liquid phase and settle at the bottom. Problems barite sag causes include well control problems, stuck pipe, cementing and casing problems, borehole instability and formation fracture. Sag is a function of the mass of the weighting material, due to the problems barite sag causes downhole, it is vital to study how best sag can be controlled with lower density (CaCO3) material.
This study aims to optimize Calcium carbonate at different concentrations and also
alter its pH to mitigate barite sag in a drilling fluid.
The two main objectives of this study are:
Investigation of salt concentration effect (CaCO3) on barite sag.
Investigation of how alteration in pH affects barite sag at different CaCO3 concentrations.


Petroleum drilling is the vital step in the achievement of oilfield exploration. This achievement is based, on the important data gotten from geological drilled. Therefore, the fundamental drilling objective are to achieve the target safely in a short time and at the lowest cost possible, with required additional sampling and evaluation limitations directed by the specific application. Drilling the wellbore is the first and the most expensive step in oil and gas industry.
Drilling fluids, which represent one-fifth (15 to 18%) of the aggregate cost of well petroleum drilling, should for the most part comply with three important requirements: they ought to be, (i) simple to use, (ii) not very costly and (iii) Environmentally friendly.
The complex drilling fluid plays a lot of functions while drilling. They are proposed to clean the well, hold the cuttings in suspension, prevent craving, and prevent formation damage. In addition, they likewise need to cool and grease up the tool.

Density is an important parameter to consider. For desired densities, greater or less than 1, water-based mud or oil-based mud can be used, respectively. The latter are proposed especially for clay formations where this density should be adequate for drilling. Generally, for both WBM and OBM, mud weight (density) can be increased by including different solids or soluble materials.
The second parameter to look at is viscosity. It is a general term used to describe the internal friction generated by a fluid when a drive is applied to make it flow. Different added substances are added to the formulation to reach optimized purposes which are contradictory sometimes. For example, mud must be adequately thick to have the ability to lift the cuttings to the surface, however meanwhile, viscosity must not be too high in order minimize friction pressure loss.

Drilling fluid loss is the last considered parameters. Generally, the volume of the drilling mud that goes into the formation through the filter cake formed while drilling. It is often minimized or prevented by blending the mud with additives. Various factors influence the fluid-loss properties of a drilling fluid, including the time, temperature, and cake compressibility; additionally, the nature, amount and size of solids present in the drilling fluid. In high-pressure and high-temperature environment, optimization of the previously mentioned three parameters is fundamental to help instability issues when drilling through shale sections.

Weighting materials or densifiers are solids material which when suspended or dissolved in water will increase the mud weight. Most weighting materials are insoluble and require viscosifiers to enable them to be suspended in a fluid. Clays and polymers are the most common viscosifier. Mud weights higher than water are required to control formation pressures and to help combat the effects of sloughing or heaving shales that may be encountered in stressed areas. The specific gravity of the material controls how much solids material (fractional volume) is required to produce a certain mud weight (Shaikh, 2010).
The ability of drilling mud to suspend drill cuttings and weighting materials depends entirely on its viscosity. With low viscosity, all the weighting material and drill cuttings would settle to the bottom of the hole as soon as circulation is stopped. One can think of viscosity as a structure built within the water or oil phase which suspends solid material. In practice, there are many solids which can be used to increase the viscosity of water or oil. The effects of increased viscosity can be felt by the increased resistance to fluid flow; in drilling this would manifest itself by increased pressure losses in the circulating system (Shaikh, 2010).
When efficient control of excessive viscosity and gel development cannot be achieved by control of viscosifier concentration, materials called “thinners”, “dispersants”, and/or “deflocculants” are added to drilling muds. These materials cause a change in the physical and chemical interactions between solids and / or dissolved salts such that the viscous and structure forming properties of the drilling fluid are reduced. Thinners are also used to reduce filtration and cake thickness, to counteract the effects of salts, to minimize the effect of water on the formations drilled, to emulsify oil in water, and to stabilize mud properties at elevated temperatures (Shaikh, 2010).
Filtration control materials are used to reduce the amount of fluid that will be lost from the drilling fluid into a subsurface formation caused by the differential pressure between the hydrostatic pressure of the fluid and the formation pressure. Bentonite, polymers, starches, thinners and deflocculants perform function as filtration control agents (Shaikh, 2010).
The pH affects several mud properties; like detection and treatment of contaminants such as cement and soluble carbonates; and solubility of many thinners and divalent metal ions such as calcium and magnesium. Alkalinity and pH control additives include: NaOH, KOH, Ca(OH)2, NaHCO3 and Mg(OH)2. These are compounds used to attain a specific pH and to maintain optimum pH and alkalinity in water-based drilling fluids (Shaikh, 2010).
Lubricating materials (lubricants) are used mainly to reduce friction between the wellbore and the drillstring. This will in turn reduce torque and drag which is essential in highly deviated and horizontal wells. Lubricants include: oil (diesel, mineral, animal, or vegetable oils), surfactants, graphite, asphalt, gilsonite, polymer and glass beads (Shaikh, 2010).
Shale stabilization is achieved by the prevention of water contacting the open shale section. This can occur when the additive encapsulates the shale or when a specific ion such as potassium enters the exposed shale section and neutralizes the charge on it. Shale stabilizers include: high molecular weight polymers (PHPA), hydrocarbons, potassium and calcium salts (e.g. KCl) and glycols (Shaikh, 2010).
Well control difficulties– At the uppermost section of the well where the density is very low, if hydrostatic pressure is less than the formation pressure, the well control situation will happen (Drilling Mud Knowledge, 2011).
Fracture formation and lost circulation – Heavy mud at the bottom of the well can facture the weak formation and it finally would result in lost circulation.
Stuck pipe – At the bottom part where heavy mud is, the chance of stuck pipe due to differentially stuck increases because higher differential pressure between formation pressure and hydrostatic pressure. Moreover, in a highly deviated-well, a barite bed can slump back and pack of the drill string (Drilling Mud Knowledge, 2011).

Pack off and lost circulation – weighting material separating from the liquid phase can pack off the drill string and lead to lost circulation.
Well bore instability – formations need sufficient mud weight to stabilize the well. If mud weight is insufficient to stabilize the wellbore, wellbore can collapse and pack the drill string. At the top part of the well where the light density is happened due to barite settling, the chance of well bore collapse increases (Drilling Mud Knowledge, 2011).

Increase gel strength and rheology – when you increase these values in drilling mud, barite settlement rate reduces. However, in deep-water environment, you need to be aware that adjusting mud rheology can make the barite sag worse (Drilling Mud Knowledge, 2011).
Monitor mud density after dilution – when the drilling mud is diluted with base fluid, the mud will be thinner therefore chance of barite sag will increase. To prevent this situation, you may need to use rheology modifiers to reduce loss of mud viscosity (Drilling Mud Knowledge, 2011).
Keep sufficient surfactant concentration – insufficient surfactant concentration in oil-based mud causes barite agglomeration. Additionally, you must not over treat by adding lot of surfactant because mud viscosity will be significantly reduced (Drilling Mud Knowledge, 2011).
Add proper amount of fluid loss additives – In water-based mud system, fluid loss additives can reduce viscosity and it will finally create barite sag in the mud (Drilling Mud Knowledge, 2011).

Mud Density – Mud weight in and out must be monitored at least 15 minutes while circulating after tripping. Typically, in the wells having this issue, while circulating, you will see the light mud first and the heavy mud from the bottom. The heaviest mud is normally coming from the bottom where there is a lot of barite settling. It is a good drilling practice to circulate until the mud weight out is equal both mud weight in. If you are in High Temperature High Pressure (HTHP) condition, mud weight correction with temperature is recommended (Drilling Mud Knowledge, 2011).
Mud losses and gains – Heavy mud at the bottom of the well can possibly fracture weak zones and it will result in losses. Conversely, light stuff at the top part of the well can allow formation fluid into the wellbore because of insufficient hydrostatic pressure (Drilling Mud Knowledge, 2011).
Standpipe Pressure – The standpipe pressure fluctuates when unconformity mud density is being moved. If the sag issue is very serious, the stand pipe pressure will be so high (Drilling Mud Knowledge, 2011).
Zamora & et al (2004); studied Improved Wellsite Test for Monitoring Barite Sag. According to this paper the Viscometer Sag Test (VST) is one of very few wellsite tests available to directly measure barite sag tendency of drilling fluids but due to its inconsistency a new lost cost improvement was made, and it involved the insertion of a thermoplastic shoe in the bottom of a thermocup. Static cells are often used to test sag in the lab, but sag severity most commonly is a result from low shear rate rheological properties measured with standard oilfield viscometer. The main aim of this paper is an improvement to the original VST sag shoe, it was modified to improve consistency accuracy of the former VST. The original VST measures the density increase at the bottom of an API mud thermocup after mixing the mud sample at 100 rpm with a standard field viscometer for 30 min while the improved VST involves the insertion of a thermoplastic “shoe” in the bottom of the thermocup before running an otherwise standard VST procedure. sloping surface on the Shoe helps to accelerate settling and to concentrate the weight material into a single collection well at the bottom of the thermocup. Consistency is helped by maintaining a constant 7-mm distance between the bottom of the viscometer sleeve and where the sleeve would touch the uppermost surface of the Shoe. Difference between Shoe and standard VST measurements for most of the fluids included in this paper. On average, the Shoe results were 0.2 lb/gal higher, but the VST values were slightly higher in about half of the cases.
Massam & et al (2004); studied A unique technical solution to barite sag in drilling fluid. According to this paper, ultrafine polymer coated barite technology in oil-based drilling fluid which are oil wetting, which can serve as a new technology in sag reduction. The ultra-fine polymer-coated barite weighting agent allows fluids to be formulated with low rheological properties without compromising the sag potential of the fluid. the ultra-fine polymer-coated barite has about 60% of its particles less than 2 microns, the high-energy wet grinding process used in the production of this product is critical in ensuring efficient coating of the barite particles which results is a stable, high-density, low viscosity oil-based slurry. Afterwards, the slurry weighting agent can be used to formulate high performance drilling fluids with minimal sag potential. The technology focuses on drilling fluids and development on additives and systems to minimize the sag potential. In this paper it was mentions that stokes law established that smaller particles tend to settle slower in a fluid, these finer particles would also result to an increase in fluid viscosity. The technology discussed on this paper mainly was minimizing barite sag by formulating drilling mud having a polymer coated barite while maintaining low rheology.
Tehrani & et al (2004); studied Role of Rheology in Barite Sag in SBM and OBM.
According to this paper barite sag is more severe in synthetic based fluid than oil-based fluid, in oil based mud and can occur over a relatively wide fluid density range 11.7-20.0 lb/gal. It can lead to density variations as high as 4.0 lb/gal. Barite sag in SBMs and OBMs is related both to the mud properties and the drilling operation rheology and dynamic barite sag was investigated in a range of invert emulsion fluids formulated with different organoclays and polymeric additives. For all the fluids investigated, dynamic sag correlated with fluid rheology at the prevailing shear rate and viscoelastic properties sag was lower in the claybased fluids tested than those formulated with polymeric additives.
Hemphill & et al (2004); studied Improved Prediction of Barite Sag Using a Fluid Dynamics Approach. According to this paper research was carried out in the accurate prediction of barite sag in deviated wellbore applying fluid dynamics, correlations in the papers were used to predict barite sag occurrence on field. Outer diameter of the inner tube and the inner diameter of the conduit, drilling fluids Herschel-bulkley rheological parameters (n, K, t0), n (flow rate, shear stress at the wall are the parameters that governs the calculation of pressure drop required to shear a pseudoplastic drilling fluid. the correlation between the conduit wall shear stress and measured dynamic barite sag can predict the incidence of barite sag in an invert emulsion drilling fluid. the correlation is said to have a very high degree of confidence.
Falana & et al (2007); studied Novel Sag Reducing Additive for Non-Aqueous Drilling Fluids. According to this paper there is lack of industrial or API standard to measure and/or identify key sag causative parameters, the viscometer sag test (VST), sag-flow loops and static aging of mud in special cell tubes, pressure bombs and dynamic high angle settling tool (DHAST™) are known examples of the laboratory methods and are said to often fail. The novel sag-reducing additive is formulated to alleviate sag in invert emulsion drilling fluids (IEDF) without increasing low-end rheological properties. However, changes in the rheological properties of Invert emulsion drilling fluid are evident when there is a sag. To quantify sag, changes in specific gravity of base mud and the base mud treated with NSRA were measured. This equation in the paper was used to calculated sag Sag (ppg) = (SGf – SGi) (8.33) where SG f is final specific gravity after rolling at high temperatures SGi is the initial specific gravity, in the experiment for this work flow properties (PV, YP, and Gels were tested for both mineral oil based drilling fluid, diesel oil based drilling fluid and synthetic based drilling fluid. the novel sag reducing additive was proven to improve suspension properties of drilling fluids, reduced fluid loss at HTHP and was compatible with oil based and synthetic based drilling fluid.
Omland & et al (2007); studied Detection Techniques Determining Weighting Material Sag in Drilling Fluid and Relationship to Rheology. according to this paper it was stated that due to the lack of a suitable sag testing technique for studying the basic mechanisms causing the settling of the barite, lots of efforts have been made to optimize properties that has an impact on the sag performance. Several methods were used in this work to study sag performance. Focusing on rheology significantly increased knowledge of different ways to prevent particulate material from settling out of the drilling fluid causing instability, the rheological behaviour of the fluid is of the outmost importance. No specific rheological parameter has yet been shown to be directly linked to the particle settling potential. This paper reviews different testing techniques available to detect the particle settling potential of the drilling fluid, and describes work performed to relate this to rheological properties. The effect of different operational sequences was studied through field cases, but these are often inconclusive due to lack of accurate data. Neither does one have a good picture of the complete operation, not knowing which elements are dominant for causing sag.
Hemphill & Halliburton (2009): studied Comparisons of barite sag measurements and numerical prediction. According to this paper most researchers agreed that barite sag can occur based on some conditions listed in the paper like barite sag is a dynamic and not a static phenomenon, barite sag occurs in deviated wellbores at angles of 40-750, barite sag occurs in drilling fluids exhibiting low viscosity, barite sag occurs while circulation with an annular velocity of 0.51m/s or less. A DHAST apparatus was filled with a drilling fluid at an angle, a rotating shaft in the apparatus which rotated at a controlled speed equivalent to 0.35s-1. When barite comes out of the suspension exposed to the shear rate domain, the solid particles slide, and the change in the centre of mass is divided by the time of each measurement (usually three hours) to get the DHAST apparatus sag rate (mm/hr). This test has been used severally on fields where barite sag had been occurring, because of the usual time-delay in getting sagging samples to the laboratory and changes in fluid chemistries being made concurrently in the field, rarely do lab received samples reflect the true nature of the mud causing problems in the field. While in numerical prediction fluid dynamics approach was used for calculations were carried out using rheological properties (measured under ambient conditions) of a sample associated with the initial barite sag event, Using the rheological properties of the sample above after static aging for 16 hours at 350°F. using both methods the potential for barite sag in the field can be easily identified.
Ibeh & et al (2008); studied Investigation on the Effects of Ultra-High Pressure and Temperature on the Rheological Properties of Oil-based Drilling Fluids. According to this paper it is vital that both the hydrostatic overbalance and the dynamic pressures are accurately modelled and managed, otherwise, losses may result. Increase in pressure increases the fluids viscosity due to its compressibility, whereas the increase in temperature increased the random motion of the molecules dissolved in the fluid. The rheology of the fluid is influenced by many factors including temperature, pressure, shear history, composition and the electrochemical character of the components and of the continuous fluid phase. A drilling fluids viscosity is directly related to the downhole variations in pressure and temperature and is a very important part of drilling engineering. Oil-based drilling fluids have some advantages when compared to water-based fluids in XHP/HT applications. In addition, oil base drilling fluids can be used to drill through most troublesome shale formations due to their inherent inhibitive nature and temperature stability. In XHP/HT wells, only a small hydrostatic overbalance can be tolerated due to the reduced margin between pore and fracture gradients, therefore it is vital that both the hydrostatic overbalance and the dynamic pressures are adequately managed, otherwise losses or influx may result. This paper presents results of extensive laboratory experiments on oil-based drilling fluids. the first fluid (A) formulation to be used in this research. The base oil was diesel and it was weighted with barite. The original fluid was obtained from the field and then improved in the lab with some additives. The fluid had a density of 18.8 ppg and an oil/water ratio of 91/9. This second (B) fluid used extensively in this research, it is a mineral oil-based fluid with a mud density of 18.0 ppg and 93/7 oil/water ratio. Average Electrical Stability (ES) was 950. Two formulations have been used B1 and B2. The difference between B1 and B2 consists of the additives used to enhance the thermal stability. Using Fluid Type B, two baseline tests were performed to investigate the effects of recipes (B1 and B2) on the thermal stability of the fluid. Both fluid formulations had a density of 18.9 ppg. The maximum temperature and pressure attained was 600°F and 33,000 psig. Fluid Type-A has been shown to disintegrate beyond 425°F and its rheological behaviour becomes inconsistent as reflected in the non-uniform increase in viscosity. The effects of temperature on viscosity of the oil-based fluids have been observed to be dominant at higher pressures. (>20,000 psig) while pressure effects prevail at lower temperatures (<350°F).
Fraser & et al (2009); Studied 4.1-SG Barite: Current application status and future possibilities. According to this paper the lower density (4.1-SG) material is said to contain 86.9wt% of barium sulphate as compared to 90.8wt% for the higher density (4.2-SG) material, quartz content was also a major difference. It was difficult to supply industry’s demand for 4.2-SG barite that complies with the API specifications while demand increased and reserves depleted. It was anticipated that, with the acceptance of the 4.1 SG material as a robust alternative to the current 4.2SG standard, the lower density materials became dominant in the marketplace. Depletion of barite reserves suitable for the supply of finished product that complied with the API specifications forced the industry to consider options. Lab testing and extensive field use have confirmed that lower density 4.1 SG barite can be successfully used in so many applications while conforming to environmental and performance requirements. To avoid the continuous depletion of higher density reserves which will be needed in future for challenging wells, it was proposed that industry (hopefully supported by an alternate API barite specification for 4.2 SG material) continues to test the viability in higher density fluids. Used in deep-water applications would contribute enormously to preserve the higher density material.
Scott ; et al (2010); studied Economic Considerations and Impacts for Using Low Grade Barite. According to this paper, low grade barite has a density lower than barium sulphate and contain lots of contaminants but in turn these contaminants impact not only on quality but also quantity SG of pure barium sulphate has proven to be higher than that of low grade barite, heavy materials such as mercury, lead are considered contaminants in barite due to increase in purchase in low grade barite. The specifications by API required a purity of 94% minimum barium sulphate, a specific gravity between 4.0 and 4.25. To properly evaluate the cost of using low grade barite, the quantity of additional low gravity solids must be considered as it reduces the quantity of drill solids that the drilling fluid can incorporate and still have acceptable fluid properties. It was evident that the negative value of using a low grade barite is higher than the original life-cycle cost estimate ton to continue production of the higher grade of barite with additional processing.
Parvizinia ; et al (2011); studied Experimental Study on the Phenomenon of Barite Sag. This article presents an experimental study conducted on barite sag behaviours of oil-based fluids. A cylindrical sag testing cell has been developed to measure the level of barite sag at different shear rates (from 0 to 0.82 1/s) and temperatures (80°F and 120°F). The cell has a rotating disk at the top to create the shear field in the cylinder, which is filled with test fluid. Pressure sensors were mounted on the wall of the cylinder to measure sag tendencies of the sample as a function of pressure gradient. Several tests were conducted on OBM fluid at different temperatures and disk rotation speeds. Density and rheological properties of the samples were measured before and after the test. The experimental results indicate significant barite sag, especially in fluids subjected to high shear rates and elevated temperature. For the fluids tested, the change in temperature had the greater influence over sag behaviour in comparison to shear rate. Results suggest that the viscosity of the oil-phase, which is very sensitive to temperature, has more pronounced effect on sag than the rheology of the mud system.
Himmatzadeh ; et al (2011); Studied the effect of pH and calcium salt on rheological properties of Xanthan gum, Carboxyl methyl cellulose blends. Xanthan gum and CMC were blended with de-ionized distilled water while continuously mixing at encompassing temperature. The outcome demonstrated Xanthan – CMC mixes in all proportions indicated shear thinning flows behaviour at 25oC. Salt addition in various pH values causes apparent viscosity reduction.
Steele ; et al (2012); studied Micronised Ilmenite – A New, Intermediate Weight Material for Drilling Fluids. The primary function of a weight material is to increase the density of a drilling fluid. Since the 1920’s, barite has successfully fulfilled this function due to its availability, cheapness, high density & relative inertness. However, there have been a few changes recently, which suggest a need for alternative weight materials. The global availability & supply of high grade (?4.20 sg) barite is diminishing rapidly, there is a need for weight materials, which provide other properties such as to facilitate ECD management, sag control, formation damage mitigation etc. There are a few weight materials such as manganese tetraoxide 1,2 or treated micronised barite 3 which satisfy some or all of these demands. They provide excellent, extra properties compared to barite, but such a high performance is not always needed for a particular application, the volumes are limited & they are more expensive. There is a need for alternative weight materials, which can provide better performance & cost, intermediate between barite & the high-end weight materials which require extra logistics and handling needs. This paper describes a new micronised, ilmenite, which offers significant advantages in the control of ECD, sag & formation damage. Tests show how it is used to create fluids with stable rheology with low PV’s ; gel strengths, even under HPHT conditions, for both water ; non-aqueous based fluids. It is denser than barite, has a better environmental profile, is highly acid soluble ; is easy to recycle. Accordingly, it provides a viable alternative product, intermediate between barite ; the more expensive ; specialised weight materials.
Teke ; et al (2012); studied Hindrance Effect on Barite Sag in Non-Aqueous Drilling Fluid. according to this paper it was stated that barite sag is mostly a dynamic phenomenon and occurs mostly in inclined wells. Oil base drilling fluids tend to sag more compared to water based. Barite sag occurs in drilling fluids exhibiting “low” low-end rheology. Barite sag usually occurs while circulating with an average annular velocities (AV) of 100 ft/min (0.51m/s) or less. Finding suitable equipment that can measure barite sag at the lab or rig site and in developing numerical methods for predicting barite sag from rheology numbers has been focused on in the past years. The hindrance model for Newtonian fluids under Stokes flow condition was extended to drilling fluids based on the reference sag rate data from DST, the hindrance model successfully predicted changes in sag rate as the barite concentration (? or mud weight) changes. The hindrance model was found to be applicable for NAF fluids even though the non-Newtonian characteristics (yield stress, shear thinning response) of the fluids were widely changed by changing the OWR and additive concentrations. Using the hindrance model, for the first time, it was quantitatively shown that the barite sag tends to be much more severe for fluids with mud weights in the range of 12.5 ppg -13.5 ppg which is consistent with the widely observed condition of worst sag in the field.
Ayoade (2013); studied The effect of pH and salt concentration on barite sag in oil base drilling fluids. According to this study it was shown in detail the effect of salt concentration in the internal brine phase of an oil base drilling fluid on barite sag. Salt concentration was varied across various fluid samples while maintaining the same mud weight throughout and also testing for sag tendencies. The effect of salt concentration on barite sag was investigated through several experiments in this study. The 15% CaCl2 drilling mud sample experienced the worst sag tendencies while the 30% CaCl2 drilling fluid sample experienced the least amount of sag. Sag gradually increased as salt concentration decreased. It was possible to control sag using smaller particles or particles having low density. The pH of oil base drilling fluid samples was also varied, and the effect of pH on barite sag was investigated, with decrease in pH, sag was increased at each concentration. The sag tendencies of the oil base fluids were experimentally determined with an enhanced viscometer sag test, the fluid sample with 35% CaCl2 had the highest gel strength values with varying CaCl2 concentration from 15% to 35%. The fluid sample with 35% CaCl2 concentration showed the least amount of sag, while the sample with 15% CaCl2 concentration showed the greatest amount of sag. As the pH value of the drilling fluid was reduced, the sag of the drilling fluid samples increased.
Nguyen ; et al (2014); studied A Quantitative Study of the Combined Effect of Drilling Parameters on Barite Sag in Oil-Based Drilling Fluids. According to this paper Drilling parameter includes pipe rotation, annular velocity, eccentricity, and inclination angle. Two levels for each parameter were considered to develop the test matrix in this study, for instance the parameter of annular velocity has two levels including eccentric drill pipe and concentric drill pipe. Barite substitutes are calcium carbonate, manganese tetraoxide, and iron titanium oxide. Barite is the most widely used weight material because it offers high density with wide availability, environmentally friendly and favourable economics. If the weather condition is bad drillers may have to shut down the well completely for days or weeks and the fluid inside the drill-string and inside the annulus is at rest. If the gellation property of the drilling fluid are not high enough, the weighting materials would settle out of the suspension causing a density difference in the fluid. To avoid stuck pipe drillers normally maintain a low pipe rotation speed, this rotational speed may cause severe sag because the shear from the pipe rotation breaks the structure of the fluid and hence accelerates the settling of the weighting materials. During no pipe rotation, there is a low flow of the drilling fluid in the annulus due to the displacement of the fluid by the drill-string. This low annular velocity may also cause barite sag. Several studies have shown that annular velocities close to 30 ft./minute results barite sag the most, this paper provided a method to extract more reliable information from this dynamic test for different type of drilling fluids. Data from the dynamic sag tester on Field Sample 1 under different shear rate sequences at T = 3200F and P = 2000 psi. In the first test, a shear rate sequence of 5, 10, 15 RPM was applied following the warm-up of the fluid to the desired temperature. The data indicates that the sag rate or settling tendency of the particulates in the fluid increases with increase in applied shear rate up to 15 RPM. The second test was run on fresh batch of the same field sample 1 where a reverse shear rate sequence of 15, 10, 5 RPM was applied to the fluid at same T and P conditions. The method showed that the “low-sag” fluids vs. “high-sag” fluids response on dynamic sag tester is significantly different based on shear history.
Fike ; et al (2014): studied Drilling Fluid Storage and Transfer Methods at Perdido. According to this paper. Recent operations have highlighted barite settling and loss of emulsion during transport can be a result of drilling fluid storage and transfer methods currently used at Shell’s Perdido spar. drilling fluid storage and transfer methods currently used at Shell’s Perdido spar and at 2014 were coping with two primary mud supply issues: loss of emulsion which is a reason barite might sag. synthetic based mud is an emulsion of water in base oil and its fluid density is manipulated by changing the concentration of barite particles. To ensure good emulsion the drilling fluid supplier adds chemicals to help ensure that the water mixes into the base oil. Despite the best chemistry, after extended periods without adequate circulation of the entire fluid volume, the dense barite particles will begin to settle out to the bottom of the fluid and the low density base oil will rise to the top of the fluid. The best method to prevent this is circulation and agitation of the entire drilling fluid volume. This density stratification indicates both loss of emulsion and barite settling in the lower tank volume. This fluid required extensive treatment that was costly in both chemicals and time. The drilling fluid tanks were circulated for one hour every four hours. This circulation scheme appeared adequate This setup may reduce barite settling on the tank bottom, but it is not being able to provide adequate circulation to the entire volume of drilling fluid in the tank. The circulating pumps and tank rolling schedule are adequate to prevent excessive barite settling and phase separation.

API Recommended Test.
The reason for API test is to certify that the drilling fluid used in time of this experiment was in good condition and meets the required standards. The test includes drilling fluid density, viscosity, pH and gel strength. Outcome of the API recommended tests are shown in table 1.
Table 3.1: Outcome of the API recommended tests
(PPG) PV AV YP 10s/10m pH
Base Sample 9.6 10
185/155 8

Varying Salt Concentration.
The calcium carbonate concentration was varied from 15% to 30%. The amount of calcium carbonate to be added was calculated using 300 grams of calcium carbonate per litre of drilling mud as the reference. Salt concentration at different percentages to be added to the drilling fluid are show in the table below
Table 3.2: Various concentration of CaCO3 at different percentages
% g/l g/400ml g/200 ml g/100ml
15 45 18 9 4.5
20 60 24 12 6
25 75 30 15 7.5
30 90 36 18 9

3. Sag Test.
The sag tendencies of the oil base fluids were experimentally determined manually using a graduated cylinder for different pH values and different salt concentrations. A graduated cylinder is a laboratory equipment used to measure the volume of a liquid and often graduated in millilitres. The oil-based mud was filled to 700ml in graduated cylinder, over time the barite tends to settle at the bottom of the cylinder. Every 2 hours for 24 hours, the settlement of barite in the cylinder is presented in millilitres.
Measuring Cylinder Procedure.
Mix the properly mud to ascertain homogeneity.
Heat the mud up to 1500C
Pour 700ml of mud into the cylinder and cover.
Record the barite settling at 2-hour interval for 24 hours
5. pH Alteration
The other part of the project is the alteration of the drilling fluids pH. The drilling fluids pH was initially at 8, but with the used of hydrochloric acid the pH was dropped to 6 and also with the use of sodium hydroxide the drilling fluids pH was increased from 8 to 10 and 12. As the pH was altered then sag test was carried out for each drilling fluid and they all had new rheological values. New rheological data were obtained at different salt concentration and pH value. A pH meter aided in the accuracy of the drilling fluids pH values.


The rheological values of the drilling fluid are a good indication of barite sag of indication of the suspension ability of the samples. Barite settling would occur in drilling fluids with low gel strength. Gel strength and yield point increased as calcium carbonate concentration increased. This result showed that the fluid sample with 30% CaCO3 had the had the most gel strength values and yield point values. Barite settling increased as gel strength reduced. Rheological values and sag result are shown in Tables 3, 4, 5, 6 and 7. Figure 1 shows Sag in drilling fluids with varying calcium carbonate concentration, figure 4 shows effects of pH change on barite sag in the drilling fluid samples at varying concentrations.
Table 4.1: Rheological Data with varying CaCO3
Rheology of sample with varying CaCO3 15% 20% 25% 30%
600 rpm (lb/100ft2) 255.00 260.50 270.00 290.00
300 rpm (lb/100ft2) 247.00 252.00 258.00 273.00
200 rpm (lb/100ft2) 230.00 237.00 246.00 248.00
100 rpm (lb/100ft2) 220.00 222.00 226.00 230.00
PV(cP) 8.00 8.50 12.00 17.00
AV (cP) 127 130.25 135 145
Yield point (lb/100ft2) 239 243.5 246 256
10-s Gel (lb/100ft2) 140 143 145 148

4.1 Sag Test Result.
The rheological values in table 4 shows the sag test results across samples with varying CaCO3 concentration from 15% to 30% at its initial pH. From the data, the fluid sample with 30% CaCO3 concentration showed the lowest amount of sag, while the sample with 15% CaCO3 concentration showed the highest amount of sag.

Table 4.2: Rheological data of samples at pH 8
Rheology of sample with varying CaCO3 ; sag results for pH 8 15% 20% 25% 30%
600 rpm (lb/100ft2) 255.00 260.50 270.00 290.00
300 rpm (lb/100ft2) 247.00 252.00 258.00 273.00
200 rpm (lb/100ft2) 230.00 237.00 246.00 248.00
100 rpm (lb/100ft2) 220.00 222.00 226.00 230.00
PV(cP) 8.00 8.50 12.00 17.00
AV (cP) 127 130.25 135 145
Yield point (lb/100ft2) 239 243.5 246 256
10-s Gel (lb/100ft2) 140 143 145 148
10-min Gel (lb/100ft2) 110 125 128 130
Temperature ?C 150.00 150.00 150.00 150.00
Sag @ 2hours 50ml 45ml 30ml 30ml
Sag @ 4hours 70ml 60ml 40ml 37ml
Sag @ 6 hours 85ml 70ml 49ml 43ml
Sag @ 8 hours 95ml 78ml 56ml 48ml
Sag @ 10 hours 103ml 84ml 61ml 51ml
Sag @ 12 hours 106ml 87ml 65ml 53ml
Sag @ 14 hours 113ml 89ml 69ml 53ml
Sag @ 16 hours 115ml 90ml 69ml 53ml
Sag @ 18 hours 116ml 90ml 69ml 53ml
Sag @ 20 hours 116ml 90ml 69ml 53ml
Sag @ 22 hours 116ml 90ml 69ml 53ml
Sag @ 24 hours 116ml 90ml 69ml 53ml
Graduated cylinder Sag
Sag (Milliliters)
Sag (Milliliters)

Figure 4.1: Sag in drilling fluids samples with varying salt concentration change in pH
Alteration in pH demonstrated changes in the rheological values from the initial drilling fluid. The gel strength of the drilling fluid dropped when hydrochloric acid was added to the mud, flocculation and fluid loss in the drilling mud were also noticed.
When sodium hydroxide pellets were added to the drilling fluid, the pH of the drilling fluid increased also showing a significant increase in the rheological values of the drilling mud. When the pH of the mud was reduced using acid sag significantly increased. At values of 10 ; 12 pH, the gel strength increased.

Figure 4.2: Drilling fluid sample at pH of 8

Figure 4.3. Drilling fluid sample showing fluid loss and flocculation
Table 4.3: Rheological data of samples with pH 10
Rheology of sample with varying CaCO3 ; sag results for pH 10
15% 20% 25% 30%
600 rpm (lb/100ft2) 247.00 252.00 255.00 260.00
300 rpm (lb/100ft2) 240.00 243.00 245.00 249.00
200 rpm (lb/100ft2) 215.00 218.00 222.30 225.00
100 rpm (lb/100ft2) 200.80 203.90 206.30 210.00
PV(cP) 7.00 9.00 10.00 11.00
YP (lb/100ft2) 233 234 235 238
AV (cP) 122.5 124.5 126.5 130.00
10-s Gel (lb/100ft2) 150.00 152.00 154.00 160.00
10-min Gel (lb/100ft2) 135.00 136.00 138.00 143.00
Temperature ?C 150.00 150.00 150.00 150.00
Sag @ 2hours 45ml 30ml 30ml 20ml
Sag @ 4hours 60ml 40ml 38ml 25ml
Sag @ 6 hours 70ml 48ml 44ml 29ml
Sag @ 8 hours 75ml 54ml 47ml 32ml
Sag @ 10 hours 79ml 56ml 49ml 35ml
Sag @ 12 hours 82ml 58ml 50ml 35ml
Sag @ 14 hours 84ml 60ml 50ml 35ml
Sag @ 16 hours 85ml 60ml 50ml 35ml
Sag @ 18 hours 85ml 60ml 50ml 35ml
Sag @ 20 hours 85ml 60ml 50ml 35ml
Sag @ 22 hours 85ml 60ml 50ml 35ml
Sag @ 24 hours 85ml 60ml 50ml 35ml

Table 4.4: Rheological data of samples with pH 12

15% 20% 25% 30%
600 rpm (lb/100ft2) 230.00 233.50 237.00 243.00
300 rpm (lb/100ft2) 228.00 230.00 232.00 236.00
200 rpm (lb/100ft2) 200.00 203.00 205.00 208.00
100 rpm (lb/100ft2) 185.00 187.00 192.00 197.00
PV(cP) 2.00 3.50 5.00 7.00
YP (lb/100ft2) 226 226.5 227 229
AV (cP) 115.00 116.75 118.00 121.50
10-s Gel (lb/100ft2) 181.00 183.00 185.00 190.00
10-min Gel (lb/100ft2) 155.00 158.00 162.00 170.00
Temperature ?C 150.00 150.00 150.00 150.00
Sag @ 2hours 40ml 30ml 25ml 20ml
Sag @ 4hours 50ml 37ml 30ml 24ml
Sag @ 6 hours 57ml 43ml 34ml 27ml
Sag @ 8 hours 62ml 48ml 37ml 29ml
Sag @ 10 hours 66ml 52ml 39ml 30ml
Sag @ 12 hours 69ml 55ml 40ml 31ml
Sag @ 14 hours 71ml 55ml 41ml 31ml
Sag @ 16 hours 72ml 55ml 41ml 31ml
Sag @ 18 hours 72ml 55ml 41ml 31ml
Sag @ 20 hours 72ml 55ml 41ml 31ml
Sag @ 22 hours 72ml 55ml 41ml 31ml
Sag @ 24 hours 72ml 55ml 41ml 31ml

Table 4.5: Rheological data of samples with pH 6
PH OF 6 15% 20% 25% 30%
600 rpm (lb/100ft2) 280.00 284.00 288.00 294.00
300 rpm (lb/100ft2) 265.00 268.00 270.00 274.00
200 rpm (lb/100ft2) 257.00 260.00 263.00 267.00
100 rpm (lb/100ft2) 237.00 252.00 258.00 247.00
PV(cP) 15.00 16.00 18.00 20.00
YP (lb/100ft2) 250 252 252 254
AV (cP) 140.00 142.00 144.00 147.00
10-s Gel (lb/100ft2) 100.00 103.00 105.00 109.00
10-min Gel (lb/100ft2) 80.00 83.00 83.00 88.00
Temperature ?C 150.00 150.00 150.00 150.00
Sag @ 2hours 100ml 80ml 65ml 50ml
Sag @ 4hours 150ml 120ml 95ml 75ml
Sag @ 6 hours 190ml 150ml 120ml 95ml
Sag @ 8 hours 220ml 170ml 140ml 110ml
Sag @ 10 hours 240ml 180ml 155ml 120ml
Sag @ 12 hours 255ml 185ml 165ml 125ml
Sag @ 14 hours 265ml 190ml 170ml 125ml
Sag @ 16 hours 270ml 190ml 170ml 125ml
Sag @ 18 hours 270ml 190ml 170ml 125ml
-Sag @ 20 hours 270ml 190ml 170ml 125ml
Sag @ 22 hours 270ml 190ml 170ml 125ml
Sag @ 24 hours 270ml 190ml 170ml 125ml
Effect of pH on sag
Sag (Milliliters)
pH 6
pH 8
pH 10
pH 12
Sag (Milliliters)
pH 6
pH 8
pH 10
pH 12

Figure 4.4: Effect of pH on sag
4.2 Sag Result Discussion.
Reduction in pH from 8 to 6: At 15% CaCO3 concentration sag was 104ML, 20% CaCO3 concentration sag was 65ML, 25% CaCO3 concentration sag was 65ML and 30% CaCO3 concentration sag was 52ML.

Increase in pH from 8 to 10: At 15% CaCO3 concentration sag was 26ML, 20% CaCO3 concentration sag was 15ML and 30% CaCO3 concentration sag was 8ML.

Increase in pH from 10 to 12: At 15% CaCO3 concentration sag was 8ML, 20% CaCO3 concentration sag was 5ML, 25% CaCO3 concentration sag was 4ML and 30% CaCO3 concentration sag was 4ML.

However, reduction in pH resulted in increase in sag and increase in pH resulted in sag decrease.

These experiment shows that sag is a function of the mass of the weighting material. It’s very possible to control sag by using materials with lower density (CaCO3). The 15% CaCO3 sample is not effective for use in wells with narrow windows or deviated wellbores. Typical salt concentrations range from 25% to 30% for industry use today. Salt concentration of 30% are highly recommended.
Fluid rheology can’t be said to be an accurate indication of sag tendency of a drilling fluid but it’s also a good indication of sag, combination with an actual sag test must occur.

Reduction in pH changes the rheology of the drilling fluid sample and causes charge reversal of the particles resulting in increase in the settling of barite.
Increase in pH changes the rheology of the drilling fluid sample results in decrease in the settling of barite.

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