Solids-Free, High-Density Brines for Packer-Fluid Applications

This paper reports the principal of operation of the electrical stability (ES) tester for oil muds, the construction of a research instrument that produces more reproducible results than the ES tester, and a series of ES tests on oil muds of varying and controlled composition. Several conclusions and recommendations are reported. Recommendations are made for improvement of the present ES tester, which contains several design deficiencies. The effects of emulsifier concentration, hot rolling, oil/water (O/W) ratio, mud density and other composition variables on ES values have been documented. Recommendations are made for the proper operation of the current ES tester and for proper interpretation of ES tester data. Introduction Oil-based muds provide a high degree of borehole stability, minimize washouts and remain stable under high temperature conditions. These muds are finding increasingly greater applications in drilling troublesome shales, hot holes, sour and sweet gas environments and highly deviated wells where other mud systems perform poorly or are inappropriate. Invert emulsion oil muds are water-in-oil (W/O) emulsions which are stabilized by emulsifiers. The water phase is a calcium chloride brine that comprises about 5% to 40% of total liquid volume of the mud. The calcium chloride concentration is adjusted to control the water activity of the mud to minimize water exchange between the mud and the formations being drilled. The solids in an invert emulsion mud are oil-wet so that they reside largely in the oil-continuous phase. The brine emulsion droplets in oil muds are thermodynamically unstable and tend to coalesce into much larger drops. In addition, the brine can water-wet the solids in the mud. Water-wet barite settles in the pits. The reduced mud weight can result in wellbore collapse and the invasion of formation fluids into the wellbore. Water-wetting and coalescence also cause the oil mud to invert or "flip" from oil-continuous to water-continuous. A water-continuous oil mud system is generally too viscous to be pumped and cart result in the loss of a well. Emulsifiers are added to an oil mud to reduce interfacial tension, to stabilize the brine droplets against coalescence and to oil-wet the weighting solids and drill solids in order to keep the system oil-continuous. The addition of emulsifiers generally stabilizes an oil mud. Maintaining a large excess of emulsifier has no apparent adverse effect on the muds and is a safe way to run an oil mud if one is concerned solely with oil mud stability. The excess emulsifiers associate as micelles and are available to adsorb on fresh surfaces introduced into a circulating mud. These surfaces can come from drill solids, from addition of weighting agent or from influxes of water from formation water flows or surface water contamination. However, in drilling a well, operators are concerned both with overall well costs and with mud costs. Consequently, good treatment criteria are needed for oil muds. How much emulsifier and which type should be added to keep the mud in good condition without overtreating? Good treatment practices can result in lower mud costs which, in turn, could lead to increased application of oil muds in mare routine wells. P. 227^

Formate brines are used as drilling, completion and packer fluids, among others due to their high specific gravity, their ability to stabilize polymers and their low corrosivity. The formate brines are basically non-corrosive to well materials due to their high pH (>9) and lack of oxidizing power. However, in case of CO2 ingress, the carbonic acid will acidify the brine and react with the formate ion and form formic acid, and render the brine corrosive. In corrosion tests in K-formate with a CO2 head space gas pressure up to 40 bar, initial corrosion rates of several millimetres per year were measured for carbon steel and 13%Cr steel by use of LPR (Linear Polarisation Resistance) and weight loss measurements. As a result of this initial corrosion, super saturation of iron carbonate will occur, resulting in formation of a stable and protective iron carbonate layer. Due to the high surface area-to- brine volumes in wells, the brine will within few days be saturated with iron carbonate, limiting the dissolution of this layer. This results in corrosion rates for carbon steel of 0.05-0.2 mm/year in the temperature range between 120 and 180°C. Addition of carbonate to the basic formate solution speeds up the formation and improves the quality of the carbonate layer. 13%Cr steel does not form the same protective layer, and has higher corrosion rates in the same temperature range. In contrast, Super 13% Cr steel (S13Cr) and higher grade stainless steels display very low rates.

This paper presents data on the performance of oil muds at high temperatures and high pressures. Included are data and discussions regarding static densities, circulating densities, thermal stability and stability in corrosive environments. The information on static and circulating densities combines PVT data, recently published methods of computing downhole transient and pseudo-steady state temperature data as functions pseudo-steady state temperature data as functions of circulating rates and geothermal gradients, and recently available rheological properties of oil muds at high temperatures and pressures. Thermal stability of various oil muds are discussed on the basis of theoretical physiochemical behavior of the constituents physiochemical behavior of the constituents as well as on the basis of laboratory aging and rheology data. In addition, data on oil base mud in the presence of hydrogen sulfide and carbon dioxide are presented. The data and analyses indicate that the two basic oil mud types, oil base and invert emulsion, have several distinct differences in performance characteristics at high temperature. It appears that the invert emulsion muds have temperature limits (at least economic) because of thermal degradation of their synthetic organophilic colloids and organic surfactants. Critical degradation may occur in a matter of hours at 500 degrees F. Oil base muds that use certain asphalts for the colloidal material have a higher temperature stability. This is because the asphalt does not degrade, at least up to 540 degrees F. and, because the asphalt is a hydrocarbon, does not need synthetic oil wetting and is in itself an emulsifier, and oil wetting agent and surfactant.

The wettability of typical drill solids and mud weighting agents in simple oil-based drilling fluids was studied with a newly developed dynamic Wilhelmy plate technique. Thin plates were cut from mineral specimens and used for wettability testing without polishing. The fluid systems studied were equilibrated brine with oils containing typical additives such as emulsifiers and organophilic clays. Thin plates of barite, hematite, quartz, marble and shale were moved through the air/oil and oil/brine interfaces while wetting forces were continuously measured in the advancing and receding directions. Without added emulsifier, quartz and shale were usually preferentially water-wetting in mineral oils/brine. The oil-mud weighting agents - barite, hematite and marble - were oil-wetting when advancing from mineral oil into brine and water-wetting when receding from the brine. If these minerals were wet with water before wettability testing, they remained water—wet when immersed in oil. In an oil mud system, solid additives should not be wet with water before addition to an oil mud. Wettability preferences of the minerals, including shale, were altered by diesel oils and by oil-mud additives. Diesel oils made the minerals oil-wet. The common oil-mud emulsifiers, such as tall oil soaps and polyamides, and organophilic clay caused the "dry" minerals to be strongly to moderately oil-wet and lowered the oil/brine interfacial tension. Excess emulsifier ensured that the solids in an oil mud remained oil-wet. But if the solids were initially wet with water, or if the oil-based mud became inverted (water-continuous), the water-wet solids clumped together and became difficult to revert to oil-wet. This troublesome problem occurs in field muds and is referred to as a "flipped" mud. Wilhelmy plate wetting results were correlated to the wetting behavior of solids in emulsions by photomicroscopy such that observed water-wet solids were correlated to measured adhesion tension indicating water-wetting and vice versa.

Laboratory tests using milled-tooth and diamond microbits compared drilling rates in water, water-base mud, oil-base mud, and specially formulated oil-base muds. The oil-base muds containing minimum colloidal material improved drilling rates with milled-tooth bits very little, but the improvement in drilling rates with diamond bits was substantial. Introduction Oil-base muds are disagreeable to use and expensive to prepare. Howeverfortunately for the drilling industrycertain things that cannot be accomplished with the current water-base systems can be carried out with oil-base muds. Most of the advantages of an oil-base mud become more important as wells are drilled deeper and deeper to find productive formations. Oil-base drilling fluids were first used to prevent damage to productive formations. These early oil-base fluids were simply viscous crude or refined oils. They were viscous in order to lift solids out of the hole and to limit the loss of the oil to the formation through seepage or filtration. Attempts were made to use calcium oxide to react with the water that inevitably became incorporated into the mud. Even at that early date, oil-base fluids had the reputation of slowing down the drilling. Later, oil-base muds were formulated with emulsifiers and surfactants to avoid water-wetting the solids. A moderate concentration of water could then be maintained for improved performance and lower cost. Oil-base muds (or invert emulsion's) did not achieve their current versatility, however, until oil-dispersible clays became available to prepare a low-viscosity mud having good suspension capabilities and filtration control at high temperature. This type of mud can give reasonable drilling rates in most situations, but in deep drilling the oil-base mud again slows drilling rates in low-permeability rock. Except for its effect on drilling rate, the oil-base mud is ideally suited for deep drilling. A good oil mud is more stable at high temperature than the best of the water-base systems. Salt sections and formations that contain water-reactive components can be drilled without difficulty. Hydrogen sulfide and carbon dioxide present neither a stability problem nor a corrosion problem when electrically problem nor a corrosion problem when electrically nonconductive oil-base mud is used. The water phase of the oil-base mud can be adjusted to prevent shale hydration and thus provide good hole conditions for the long periods required to dull a deep hole. All these advantages made it worthwhile to explore the possibility of improving the drilling rate of oil-base mud in rocks of low permeability. Background In 1958 Moore used laboratory drilling equipment to study the effect of apparent viscosity on drilling rate in Indiana limestone (approximately 10 md). He tested at a weight on bit of 1,000 lb, 60 rpm, 5 gal/min, and a differential pressure of 500 psi. He ran tests in a bentonite mud and in water to which glycerine had been added to increase its viscosity. He found that the viscosity created with either technique produced roughly the same effect on drilling rate. Following are some of his conclusions:A viscosity increase imparted to a liquid system by any means will tend to reduce drilling rate.There appear to be two logical reasons why viscosity slows down the rate of rock penetration: JPT P. 507

This paper discusses an approach used to assess liquid film erosion/corrosion effects in the tubing strings of sour, high-rate, wet gas producers. This was done as an alternative to API RP 14E, which utilises an empirical erosional velocity factor "C" to estimate maximum velocity limits to minimise the potential for tubing metal loss from erosional effects. Many RasGas wells are completed with a full L-80 carbon steel or a combination L-80/Corrosion Resistant Alloy (CRA) production string. Once on production, a thin iron sulfide scale develops on the tubing wall significantly retarding the rate of metal loss due to internal corrosion. However, shear stresses generated from the condensate/water film flowing along the tubing wall could potentially remove this protective iron sulfide coating and expose fresh metal to much higher corrosion rates. This paper describes the approach adopted to assess the magnitude of shear stress created across a range of flow conditions including well production rates, fluid properties, and completion sizes using transient 1D flow simulation and more detailed 3D computational fluid dynamics modelling. The results will be used to design future laboratory experiments to assess the effect of these stresses on the integrity and effectiveness of the iron sulfide scale in reducing corrosion rates. Introduction RasGas Company Limited initiated a study to investigate the potential effect of high flow velocity on the stability of iron sulfide scales formed in carbon steel tubing during late field life when the wells will be required to maintain high rates at low wellhead pressures. Higher flow velocities will generate higher shear stresses that might be capable of stripping iron sulfide scale leading to high general corrosion rate and/or severe localised corrosion. The former will be expected in the case of uniform scale erosion while the latter is expected in the case of non-uniform scale erosion. In order to meet the study objective, the first step is to understand the flow behaviour (wall shear stress, flow regime and temperature distribution) in the tubing string. Four different tubing strings were investigated: a 7-inch monobore-vertical (MB-V) and deviated (MB-D), a 9-5/8 inch x 7 inch bigbore-vertical (BB-V) and deviated (BB-D). The completion schemes for MB and BB wells are illustrated in Figure 1. 1-D flow simulations using a Transient Flow Simulation Software (TFSS) were conducted to determine the flow regime, wall shear stress, and temperature distribution and the portion of liquid flowing as wall film in the tubing strings. 3-D Computational Fluid Dynamics (CFD) simulations were also conducted to determine the wall shear stress at specific locations (X-overs) where there is a change in internal diameter of the tubing string that is greater than 10%. The objective of these simulations was to obtain shear stress predictions that would be utilised in a customised test loop to establish the stability of the iron sulfide film. If this film is not stable at the predicted shear stresses, then the wellbore integrity management programme would have to be focused on corrosion protection since historical well corrosion monitoring data has established high corrosion rate in tubing strings where the iron sulfide film has not been formed.

Corrosion control using inhibitor is an effective method to protect carbon steel from corrosion. Due to environmental toxicity of chemical inorganic corrosion inhibitors (synthetic), green inhibitors are potentially to develop. In atmospheric conditions, green vapour corrosion inhibitors are the best solutions to replace the uses of inorganic corrosion inhibitors. This research used chemical acid extraction from the key lime (citrus aurantiifolia) leaves and seeds. They are used as the main ingredients to produce this effective green corrosion inhibitor. The experiments investigated effects of corrosion inhibition on corrosion rate of low carbon steel in 3% NaCl solution using both fog salt chamber and electrochemical cell. Using salt fog chamber to represent atmospheric conditions, and corrosion rates are evaluated visually and calculated using weight loss methods. Corrosion rate on electrochemical cell were calculated using linear polarization resistance (LPR) methods. All of the experiments were set in natural conditions at pH 7. Using weight loss for three days exposure time, the efficiency of the inhibitor reached 82.39%.

Acidizing deep carbonate formations by Hydrochloric acid (HCl) is a complex task due to high reaction and corrosion rates. Mixing organic acids with HCl is a typical method to reduce the acid's reactivity and corrosivity. Lactic acid has not been investigated completely in the area of carbonate acidizing. Lactic acid has a dissociation constant similar to formic acid, which is approximately 10 times larger than acetic acid. Therefore, the objective of this work is to compare lactic/HCl blends with plain HCl and formic/HCl blends. Corrosion tests were conducted at high temperature on C-95 steel coupons to investigate associated corrosion damage. Coreflood tests were performed on Indiana limestone cores to mimic matrix acidizing treatment and to investigate amount of pore volumes required to breakthrough. All blends were prepared to be equivalent to 15 wt% (4.4 M) HCl for comparison. Lactic and formic acid concentrations were set to be (0.5 or 1 M), and HCl concentration was calculated as appropriate to reach a blend with strength of 4.4 M. In terms of corrosivity evaluation, blends of lactic and HCl acids showed a corrosion rate of up to 1.97 lb/ft2 at 300°F. The formic and HCl blend showed a corrosion rate of 1.68 lb/ft2 at the same temperature. The difference in corrosion rates between the two mixtures is due to molecular weight difference between lactic and formic acids. When both acids were prepared at 1 M, lactic acid blend required more HCl to be equivalent to 15 wt% HCl acid which was associated with an increase in corrosion rate. Coreflood results established acid efficiency curves for lactic/HCl acid blends. The curves highlighted the correlation between acid-core reactivity, injection rate, and dissolution pattern. Lactic/HCl blend was less reactive than formic/HCl mixture as the last required lower injection rate to obtain optimum pore volume to breakthrough at 300°F. Lactic/HCl blend was able to generate an optimum dissolution pattern as a dominant wormhole was shown on tested core plugs inlet face. This study expands the investigation of lactic acid utilization in carbonate acidizing. Major advantages rendered by using lactic acid with HCl include: (1) favorable dissolution pattern due to lactic acid being less reactive than HCl or formic acids, and (2) less corrosion rates comparing to HCl, that can reduce allocated costs for maintenance and replacements.

Stem incorporation of gibberellins (GA4/7 60:40) by injecting a liquid formulation or implanting a solid formulation was evaluated for promoting sexual reproductive development and for effects on vegetative development and foliage chlorosis in seedling and grafted white spruce, Piceaglauca (Moench) Voss; seedling Norway spruce, Piceaabies (L.) Karst.; and jack pine, Pinusbanksiana Lamb., seed trees. Spruces were treated with a single application of 0.76 or 1.53 mg GA4/7 per square centimetre of stem cross-sectional area at breast height during the late stage of shoot elongation (June 9 for white spruce and June 19 and 20 for Norway spruce). Jack pine was treated with a single early (July 5) or late (August 15) application of 1.53 mg GA4/7/cm2 or a split early–late application of 0.76 mg GA4/7/cm2. Results were evaluated in the subsequent season (i) by counting seed and pollen strobili, developing vegetative shoots, latent vegetative buds, and dead buds and (ii) by assessing foliage chlorosis and mortality. The numbers of seed strobili were increased by injections of GA4/7 at low and high application rates on seedling white spruce and Norway spruce and by the high application rate on grafted white spruce; implants were effective on seedling white and Norway spruce at the high application rate. In jack pine, the number of seed strobili was not increased by GA4/7. The numbers of pollen strobili were not significantly increased by GA4/7 treatments to white spruce or Norway spruce but were increased on jack pine by a single early injection at the high rate and split injections at the low rate. The number of developing vegetative shoots was reduced by GA4/7 injections at both rates on white spruce grafted trees and Norway spruce; the implants reduced them only on the grafted white spruce given the low rate. For the spruces, treatments with GA4/7 did not influence bud mortality. Foliage chlorosis and mortality, evident on jack pine but not on white or Norway spruce trees, was more severe with injections than with implants.

Effect of miscibility and injection rate on water-saturated CO2 Injection

The brain metabolic pattern of patients with winter seasonal affective disorder with and without light treatment was determined by positron emission tomography. Compared with controls, patients with seasonal affective disorder with and without light treatment had globally lower metabolic rates, relatively lower superior medial frontal cortex rates, and somewhat higher basal ganglia rates. Patients receiving light treatment had a relatively higher rate in an occipital region of interest containing the primary visual cortex. Patients without light treatment had relatively higher metabolic rates in right parietal and medial orbitofrontal cortex and lower rates in the left parietal cortex. Patients not receiving light treatment had a hemispheric metabolic asymmetry (left greater than right) for the midprefrontal cortex located 67 mm above the canthomeatal line. The right side of this region, previously found reduced in manic-depressive illness and schizophrenia, was decreased primarily in patients with seasonal affective disorder with fewer atypical depressive symptoms. These "abnormal" prefrontal and parietal cortex regions appeared highly "coupled" in the patients with seasonal affective disorder.

Summary The potential for macroemulsions to cause formation damage during drilling with emulsified drilling fluids [oil-based mud (OBM)] has been studied for consolidated low-to-medium-permeability sandstone. Two types of emulsified drilling fluids were used, one with mineral-based (MB) oil and one with synthetic-based (SB) oil. The emulsions in tested OBM were found to be stabilized both by emulsifiers and particles (organoclay and drilled solids). At low shear rates, aggregates of water droplets and particles were observed by microscopy. In bulk experiments, the stability of emulsions formed by the mixing of mud filtrates and reservoir fluids was found to depend on the compositions of emulsified drilling fluid and crude oil. These emulsions were found to cause severe formation damage in corefloods at 90°C. The damages were partly removed during aging at higher temperatures (120 and 150°C). At 90°C, the emulsions appeared to be more stable in cores than in bulk. The potential for emulsion invasion will be highest during the spurt period, especially if the emulsions in the muds are not stable. The amount of emulsion invasion will increase with filtration pressure. Creation of emulsion in the oil reservoirs will be easiest at high shear rates (e.g., in the spurt period and in the start of the oil production) and high concentrations of emulsifiers in the mud filtrate and reservoir oil. The risk for emulsion invasion and creation of emulsion during drilling can be reduced by avoiding high overbalanced pressure and minimizing the fluid loss. The potential for the creation of emulsions during start of production can be reduced by starting with low drawdown. Formation damage caused by emulsions can be nonpermanent. Because emulsions are thermodynamically unstable, the potential for permanent damage caused by emulsions will usually be lower at higher temperatures (studied mud systems showed a change between 90 and 120°C). Mechanisms for stabilization and, thereby, also for breaking of emulsions depend on the compositions of the mud filtrate and the reservoir fluids. If the damaged area is swept by the produced oil, removal of emulsions by dilution with the oil can be possible. Use of synthetic oil instead of the crude oil in laboratory experiments can give incorrect estimates of the potential for formation damage caused by emulsions. Short laboratory experiments can also give excessively high estimates of the potential for permanent emulsion-related formation damage.

Laser Shock Peening (LSP) is a surface treatment technique for metallic materials. It induces plastic deformation at the surface of up to around 1 mm in depth. This process introduces residual stresses that lead to strain hardening, and potentially improvements in fatigue, stress corrosion cracking (SCC) and general corrosion behaviour in many, but not all, corrosive media. In this paper, two specimens made of AISI 304L stainless steel, one LSP-treated and one un-treated, were tested at 280 °C and 8 MPa in VVER (or PWR) primary circuit water chemistry using in situ Electrochemical Impedance Spectroscopy (EIS). This experiment serves to qualify the influence of LSP on the changes in corrosion behaviour in high-temperature, high-density water. The residual stress (RS) measurement of the surface showed a compression RS. Before LSP treatment, RS at the surface was 52.2 MPa in the rolling direction 0°RD and 10.42 MPa in the transverse rolling direction 90°RD. After the treatment, surface RS was −175.27 MPa and −183.51 MPa for Scan and TScan directions, respectively. The effect of compressive RS at the surface was studied and showed an increase in corrosion rate. The analysis of oxide layer by SEM revealed differences between LSP-treated and untreated AISI 304L specimens and their connection to corrosion rates.

Manganese (Mn) and zirconium (Zr) are two common alloying additions in magnesium (Mg) alloys. Both of these elements, while having low solubilities in Mg, each serve a specific purpose when added to Mg. Mn is often added to improve the extrudability and formability of Mg alloys and in aluminium (Al) containing Mg alloys to produce the Al8(Mn,Fe)5 phase which is able to remove iron (Fe) impurities to dramatically improve the corrosion resistance. Zr is incorporated in Mg mainly due to its unique ability to act as a grain refiner to greatly reduce the grain size and hence improve the mechanical properties of Mg. The effect of Mn alone on the corrosion of Mg and subsequent Fe impurity levels in the absence of any Al alloying addition is not well documented. Furthermore, the independent role that Zr has on the corrosion of Mg and Mg alloys has also not been reported thoroughly. In this study, Mg alloys containing various levels of Mn, Zr and Fe alloying additions in binary, ternary and quaternary combinations were produced and examined via SEM, EDX and EBSD techniques. The corrosion rates and morphologies of Mg alloy samples were examined via electrochemical polarisation and immersion testing. It was discovered that Zr additions, while beneficial in being able to remove Fe impurities, has a negative impact on the corrosion rates of Mg. Zr is able to increase both the anodic and cathodic reaction kinetics of Mg, thereby increasing the corrosion rate. Zr dissolved in the Mg solid solution was shown to act as an ‘anodic activator’, increasing the anodic reaction kinetics and the rate of Mg dissolution. Zr not dissolved in solid solution was present as Zr particles embedded in the Mg matrix. These Zr particles were efficient local cathodes, enhancing the cathodic reaction. The difference in electrochemical potential between these, essentially pure Zr, particles and the surrounding Mg matrix lead to the formation of micro-galvanic couples at open circuit, which increased corrosion rate. Mn was observed to slightly decrease the cathodic reaction kinetics of Mg when included as an alloying addition. This is rationalised on the basis that Mn will interact with Fe, and not on the basis that Mn can support reduction reactions at lower rates than Mg. This notion also appreciates that there is no Mg metal that has 0% Fe. However, beyond Mn additions of ~2 wt.%, Mn particles which formed in the Mg matrix increased the corrosion rate through the formation of micro-galvanic couples with the Mg matrix. While Mn additions in this study were ineffective at removing Fe from the alloy system, Mn was found to be capable of rendering Fe impurities less detrimental to Mg. Mn additions were found to increase the tolerance limit of Fe in Mg. As such, higher levels of Fe were necessary to increase the cathodic reaction kinetics required for increased corrosion rates. It was observed that the Mn additions form an intermetallic phase with the Fe impurities. At low Fe levels these phases appeared to be Mn particles with Fe dissolved in solid solution within these particles. At higher Fe levels, there were large Fe particles encapsulated by a layer of Mn. It is proposed that this interaction between Mn and Fe decreases the electrochemical potential difference between the Fe impurities and the Mg matrix in a similar manner to the Al8(Mn,Fe)5 phase observed in Al-containing Mg alloys, thereby, decreasing the driving force to increase the cathodic reaction kinetics through micro-galvanic coupling. This work has elucidated the interactions and effects of Mn and Zr additions on Mg and has shown that Zr is inherently detrimental to the corrosion resistance of Mg and that Mn can interact with Fe in Mg to reduce the impact that Fe impurities have on Mg alloys in the absence of Al.

Introduction Completion problems during the cementing of casings or liners in wellbores have confronted the oil and gas industry for many years. Generally, after the borehole has been drilled, the drilling mud employed is displaced by the cement used in cementing the casing or liner. Compositions and properties of drilling muds and cement slurries vary widely. Such variation may result in detrimental physical and chemical reactions at the interfacial contact. For physical and chemical reactions at the interfacial contact. For example, when a high-viscosity, high-density drilling fluid is used, the incompatibility may contribute to channeling in the annulus and may prevent a satisfactory cement-to-formation bond. As a result, communication may occur between zones and possibly even to the surface.In view of the persistence of those problems, a serious need was recognized for a single type of spacer fluid that could be employed effectively between the cement slurry and any type of mud. Criteria for Development The following criteria were established as goals for research efforts in developing a universal spacer fluid:1. It should be compatible with all oil-base muds, invert-emulsion muds, and water-base muds, including chemical gel muds and polymer muds.2. It should not affect cement slurry viscosity, especially high-weighted cements at elevated temperature.3. It should not appreciably change the pumping time of cement slurries.4. It should allow for being weighted to any density required in the field.5. It should be able to tolerate high solids, as mud cake may be picked up, adding to what often is already a high solids content.6. It should tolerate the addition of wetting agents, dispersants, friction reducers, and retarders when needed.7. It should keep the calcium from cement slurries out of water-base muds and, especially, out of polymer muds.8. It should have low-fluid-loss properties.9. Its flow properties should permit turbulence at low pumping rates for better mud removal.10. It should be usable between various types of incompatible drilling fluids during displacement.11. It should be easy to mix and handle in the field.12. It should allow for the use of a variety of fluids in formulating the liquid phase so that specialty fluids are not necessary. In most cases the fluids are already on location.A field survey was conducted on several wells in South Texas and Mississippi to determine what cementing problems were being encountered with various drilling fluids and cements. The survey indicated that oil-base fluids and invert emulsions cause most of the problems. This is especially true when the oil-base mud contains a high-salinity internal phase composed of saturated sodium chloride or calcium chloride. As compatibility with oil-base muds and invert-emulsion muds as well as compatibility with aqueous slurries is necessary for an ideal spacer fluid, an emulsion was considered for development. JPT P. 856