|1.||An oil or gas well fluid which comprises a liquid phase having dispersed therein finally divided panicles of caicium and/or magnesium formate.|
|2.||A fluid as claimed in claim 1 in which the liquid phase comprises a concentrated aqueous brine.|
|3.||A fluid as claimed in claim 2 in which the liquid phase comprises an oilbased liquid phase.|
|4.||A fluid as claimed in claims 3 in which the liquid phase comprises a concentrated aqueous brine emulsified in an oil.|
|5.||A fluid as claimed in any one of claims 2 to 4 in which the salt or mixture of salts of the brine share at least one common ion with the finelydivided particles of calcium and/or magnesium formate.|
|6.||A fluid as claimed in claim 5 in which the brine includes at least one dissolved alkali or alkaline earth metal formate.|
|7.||A fluid as claimed in claim ό in which the brine is a saturated solution of calcium or magnesium formate.|
|8.||A fluid as claimed in ciaim 7 which comprises a saturated solution of calcium formate having dispersed therein finely divided particles of calcium formate.|
|9.||A fluid as claimed in claim 7 or ciaim 8 which additionally includes magnesium hydroxide and or carbonate as solid powders to increase the pH.|
|10.||A fluid as claimed in any one of claims 2 to 9 in which the finely divided particles are of calcium formate and the brine is based on caicium nitrate, calcium chloride, calcium bromide, combinations of these, or caesium formate, rubidium formate, potassium formate and sodium formate or mixtures of such saits.|
|11.||A fluid as claimed in any one of claims 1 to 10 in which the finely divided calcium or magnesium formate is present in an amount of from 50 to 500 g.l"1 of the well fluid.|
|12.||A fluid as claimed in any one of claims 1 to 1 1 in which the finally divided calcium or magnesium formate has a panicle size in the range 1 to 300 μm.|
|13.||A fluid as claimed in any one of claims 1 to 12 which additionally comprises one of more components selected from viscosity improving agents, polymers which confer enhanced fluid loss control, crystallisation modifiers or inhibitors and clay stabilisation additives 14 The use of calcium and/or magnesium formate as particulate solid in an oil or gas well fluid. 15 The use of finely divided paπicies of caicium and/or magnesium formate in well fluids for workover and completion of an oil or gas well. 16. A method of conducting completion or workover operations on an oil or gas well by passing a well fluid into or through a permeable oil or gasbearing rock stratum and which compπses: i pumping down the well to a position adjacent the oil or gas bearing stratum a well fluid having dispersed therein finely divided paπicies of calcium and/or magnesium formate: ii applying pressure to the well fluid to force the particles of calcium and/or magnesium formate to bridge across the pores of the permeable stratum to reduce the permeability of the stratum. iii. conducting completion and/or workover operations on the well: and iv subsequently removing the paπicies from the pores of the rock stratum by passing a well fluid which is undersaturated in respect of calcium and/or magnesium formate as appropriate over the stratum to dissolve the solid calcium and/or magnesium formate thereby restoring the permeability of the stratum. 17 A method as claimed in ciaim 13 in which the well fluid compπses a saturated aqueous solution of an alkali or alkaline earth metal formate having dispersed therein finely divided particles of calcium and/or magnesium formate. 18. A fluid as claimed 14 in which the well fluid comprises a saturated solution of calcium formate having dispersed therein finely divided particles of calcium formate.|
This invention relates to oil and gas well fluids and in particular to such fluids which contain solid paniculate materials ana which have good fluid loss control properties. Oil and gas well fluids are used in the drilling, completion and wor over of oil and gas wells. Such oil and gas well fluids may be water-based and typical water-based well fluids are aqueous solutions of salts, particularly solutions of inorganic salts, especially halide salts, of alkali or alkaline earth metals. Another type of oil and gas well fluid which is commonly used is a fluid which is based on an invert emulsion which comprises a two-phase system of an aqueous phase emulsified in an oil. e.g. an aqueous phase emulsified in diesei oil or kerosene.
Normally the weil fluid will have a density which is sufficiently high that the column of well fluid has a hydrostatic pressure which is greater than the pressure exerted by the fluid in the rock strata of interest. The excess of the hydrostatic pressure over the pressure exerted by the fluid in the strata prevents fluid escaping from the strata. However, this e.xcess of pressure tends to force the well fluid into the strata, which is undesirable. Well fluids are usually required to have properties which restrict loss of the well fluid into the strata i.e. they have so-called fluid loss control properties. Thus. it is a common practice to include fluid loss control agents which restrict and'or prevent this loss of well fluid. An alternative approach is to piace a smail volume of a weil fluid with good fluid loss control properties, a so-called fluid loss piil. in the region of the well adjacent the exposed strata with the necessary hydrostatic pressure being provided by placing a clear dense unmodified brine on top of the piii.
Commonly, fluid loss control agents include a combination of three components: i finely divided solid particles which bridge the throats of the pores of the permeable strata of interest and which are known as bridging agents ; ii polymers, e.g.. xanthan gum and hydroxyethyl cellulose which increase the viscosity of the well fluid and thus improve the suspension properties of the fluid; and iii conventional fluid loss polymers, e.g.. starch, modified starch or derivatised cellulose.
Three types of bridging agent have been suggested:
l Insoluble solids, e g bentonite or Danum sulphate Such solids suffer from the disadvantage that thev are insoluble in most solvents and solid particles remaining m the pores of the rock strata cannot be dissolved out This may permanently damage the permeability of the reservoir rock strata π Acid soluble paniculate materials, e g calcium carbonate or dolomite, are frequently used because thev can oe removed from the pores of the strata by subsequent acid treatment in Sized sodium chloride particles suspended in saturated sodium chloride bnne can be used as. described in L ' S Patent Specifications os 4175042 and 4186803 In this case the Darticulate mateπal is readilv removed bv washing with water or undersaturated bnne The aDi tv to remove soαium chloride by non-aggressive fluids of low conosion potential offers great advantage
This third type of bπdging agent generallv performs very well, but there are circumstances in which use of sized sooium cnloπde panicles is inaDpropπate or disadvantageous and some brines are incomDatible with soiid sodium chloride For example, sodium chloπde panicles cannot be used in potassium chlonde or caesium chloπde bπnes In potassium cnloπde bnne the addition of solid sodium chloride causes precipitation of potassium chlonde In caesium chlonde bnne reaction between the bnne and the soαium chloride causes the solid phase to change from sodium chloride to a sodium-caesium cnloπαe double salt In both cases the precipitation or recrystaJlisation process destroys the oπginal carefully controlled size distribution of the sodium chloπde parades thus adversely affecting the fluid loss control properties
Oil-based oil and gas well fluids compnse a two-phase system of an aqueous phase emulsified in an oil. e g m diesei or kerosene The aqueous phase is usually calcium chloπde or sodium chloride bnne. --;ια the concentration of the dissolved salts can be vaned over a wide range The fluid contains wetting agents to bnng about emulsification of the aqueous phase and to ensure that rock cuttings and the exposed borehole face are maintained in an oil wet condition A pπncipal advantage of oil-based fluids is that they ensure that water sensitive rocks are always oil wet and therefore protected from the aαueous ingredient
Other components which may be used in such oil-based fluids include organophilic clay, the function of which is to provide rheology, and weighting/ ridging agents are usuailv included in the form of finely divided banum sulphate or limestone. It can be very difficult to remove these tine paniculate materials which remain lodged in the he pores of the rock strata. Limestone is soluble only in acid, and barium suiphate is insoluble in virtually everything. Attempts have been made in the past to include a soluble paniculate material in the form of finely ground sodium chloride, but tests were invariably unsuccessful.
Inevitably the sait is affected by the dispersed aqueous phase. Observed effects included dissolution of the sait in the dispersed brine droplets, and a pronounced tendency for the salt panicles to grow.
The present invention is based on the discovery that calcium formate can be used very successfully as a soiid panicuiate material in oil and gas well fluids, that is in both aqueous-based and oil-based oil and gas well fluids. European Patent Specification EP 0259939 B describes the use of formate salts as components of halide brine-based well fluids, especially sodium chloride based brines, in which the formate salt acts as a preservative for certain hydrocolloid polymers, but it does not refer to the use in fluids of formate salts in paniculate form.
The present invention provides an oil or gas well fluid which comprises a liquid phase having dispersed therein rineiy divided panicles of calcium and/or magnesium formate.
The oil or gas well fluid may compπse an aqueous liquid phase, e.g.. an aqueous phase of a concentrated aqueous bnne or it may comprise an oil-based liquid phase for example an aqueous phase emulsified in an oil. e.g.. a concentrated aqueous brine emulsified in an oil such as diesei or kerosene.
The concentrated aqueous brine which may itself comprise the liquid phase of the oil or gas well fluid or which may be present in the fluid as an emulsion in an oil phase is a salt solution which has little or no tendency to dissolve the calcium and/or magnesium formate. In particular the solubility of calcium and/or magnesium formate in the brine will typically be less than 20 g.l "1 and more usually less than 10 g.l "1 . As is described below, the brine can be a saturated solution of calcium or magnesium formate and in
this case the solubi tv of the solid calcium or magnesium formate, which is effectively additional to the dissolved matenal in the bnne respectively is regarded as zero The low solubihtv of the calcium and/or magnesium formate in the bnne can be met if the bnne shares a common ion with the dispersed solid A further possibility is that the bnne contains sufficient dissolved salt that the effective amount of water available to dissolve the suspended solid is sufficiently small that the dispersed solid does not have significant solubility in the bnne
In particular, the invention provides an oil or gas well fluid which compπses a concentrated aqueous brine including at least one dissolved alkali or alkaline earth metal formate having dispersed in the fluid finely divided particles of caicium and/or magnesium tormate
The invention further includes the use of calcium and/or magnesium formate as a paniculate solid in an oil or gas well fluid
Calcium formate is particularly userul in the fluids and m the methods of the invention and the use and/or inclusion of calcium formate forms a specific aspect of the invention In this context, the invention included a well fluid of the invention which compπses a bnne wmch is a saturated aαueous solution of calcium formate and m which the suspended solid is finely divided calcium formate
The bnne is formed from a salt or mixture of salts dissolved in water In order to reduce the tendency of the dispersed solid to dissolve in the bnne it is verv desirable tnat the saιt(s) of the onne snare at least one common ion with the dispersed finely divided particles of calcium or magnesium formate Well fluids of the invention having a common ion between the bnne and the dispersed solid form a particularly useful separate aspect of the invention Thus, especially where the finely divided particles are of calcium formate, the salt forming the bnne can be a calcium salt, e g calcium nitrate, calcium chloπde. calcium bromide or combinations of these, e g calcium bromide and caicium nitrate Formate-based bπnes can also be used e g those based on alkali metal salts, e g caesium formate, rubidium formate, potassium formate and sodium formate or mixtures of such salts Other bπnes e a a bnne based on sodium nitrate can also be used However, particularly where a low density fluid is required, it is verv useful to
use a brine based on caicium formate, especially where the finely divided panicles are of calcium formate.
Calcium formate has a low temperature coefficient of solubility; its solubility is 16.2 g. per 100 ml water at 0°C and 1 S.4 g. per 100 ml water at 100°C. This low temperature coefficient of solubility contributes to the performance of calcium formate as a fluid loss control material. The smail fluctuation of solubility with temperature assists in the preservation of the particle size distribution and thus of the fluid loss control properties.
The limited solubility of calcium formate offers the possibility of designing a well fluid with good fluid loss control properties of significantly lower density than is achievable with systems based on sodium chloride. A comparison of the relevant densities is as follows:
Density: Brine Brine - 143 g.l- 1 of particuiate salt
Calcium formate ! . 1 1. 14 Sodium chloride 1.2 1.26
In many circumstances, this lower density is a significant advantage. Thus, in wells which are near depletion, or otherwise of low pressure, the hydrostatic pressure of a column of sodium chloride-based weil fluid can give an excessive overpressure and can cause great difficulties during drilling or well intervention operations. The availability of a lower density fluid in such circumstances can avoid such problems.
.Although the solubility of calcium formate in water is lower than that of sodium chloride, the formate is still readily soiubie. and the paniculate solid can readily be removed from the rock strata using water or undersaturated brine.
The natural pH of brines based on calcium formate or other brines containing suspended calcium formate is 7 to 8, although the presence of other acidic, basic or buffering species may alter the actual pH of a particular brine. During drilling or completion operations it can be desirable to operate at somewhat higher values of pH. Commonly such increases of pH are achieved by adding readily soluble bases such as sodium hydroxide or carbonate. In the presence of calcium formate care is required if such alkalis are used as increasing the hvdroxvl or carbonate ion concentration can lead to precipitation of calcium hydroxide or carbonate. Indeed, if sodium hydroxide is used
the pH could be raised so high that xantnan ( if present) will be precipitated In calcium formate-containing systems it is desirable to use magnesium hydroxide and/or carbonate as solid powαers to increase the pH These magnesium bases can readily raise the pH of the bnne to a maximum of about 10. but as they are substantially less soluble than their calcium counterparts they are mucn less iikely to cause the precipitation of the conesponding calcium bases The use in brines containing calcium formate (in solution and/or as suspended solids) of magnesium oxide and/or hydroxide to increase the pH of the bnne and particularly to provide brines having a pH in the range about 8 to about 10 forms a specific aspect of the invention Calcium formate is a particularly gooα paniculate matenal for use in formate brines
The h gh concentration of formate in solution generates a common ion effect further limiting any tendency of the calcium formate to dissolve The commonality between the anions in the bnne ana the paniculate mateπai greatly reαuces the chance of double decomposition reactions Similarly, in calcium nitrate, calcium oromide and calcium nitrate/bromide bπnes the high concentrations of calcium m the bπnes means that the common ion effect suppresses αissolution of the caicium formate Further, the commonality between the bnne cation and the cation of the particulate material reduces any tendency for precipitation reactions Sodium chlonde solids have the disadvantage that thev are incompatible with potassium formate bπnes and with calcium nitrate bπnes A dense brine may be prepared from potassium formate, but concentrated solutions of potassium formate react with solid sodium chloπde The double decomposition reaction gives rise to sodium formate which has a much lower solubility than that of the potassium salt. The precipitated sodium formate tends to cause such dispersions to set solid and become unusable If the amount of suspended sodium chloπde is sufficiently small that the mixture does not set solid, the double decomposition reaction will still lead to a major change in the panicle size distπbution. in particular removing fine particles, and the fluid loss control properties of the the well fluid are seπously impaired. Calcium formate as the particulate solid does not suffer from this problem In calcium nitrate brines the introduction of paniculate sodium chloride causes a large increase in the
viscosity of the brine The mechanism ot this effect is not fully understood but is probably related to the introduction of a foreign cation (1 e sodium) which may lead to precipitation reactions Similar consiαerations apply to dense bπnes oased on mixtures of calcium nitrate and calcium oromiαe The viscosity increase makes such combinations of little use Again using calcium formate as the paniculate solid substantially avoids the proolem
The finely divided calcium or magnesium formate is tvpicallv used in an amount of from 50 to 500, particularly 75 to 250 g 1 of the well fluid In anv particular application the amount will be chosen to provide the desireα properties in the well fluid Particularly when the well fluid is to be used to seal a rock formation as part of completion or workover operations the particle size of the finely divided solid calcium or magnesium formate will be chosen to suit the application Tvpicallv, the panicle size will be in the range 1 to 300 m paπiculariv 1 to 75 urn Fineiv divided solids, particularly of calcium or magnesium formate, which have a panicle size and/or size distπbution which is selecteα for a specific purpose are referred to as sized solids
The well fluids of the invention can include other components commonly used in well fluids, such as viscosity improving agents otherwise known as thickening agents, polymers which confer ennanced fluid loss control, crystallisation modifiers or inhibitors and clav stabilisation additives Viscositv improving agents are tvpicallv water-soluble polvmers which confer increased viscosity or pseuαoplasticitv on the fluid These include poiysaccnandes, e g starch, modified starch or xanthan gum, polymers of bacteπal oπg , e g succinoglycan. cellulose deπvatives. e g carbomethoxvcellulose or hvdroxvethylcellulose. or other water-soluble polymers, e g guar gum, locust bean gum and similar polymers which increase the viscosity of aqueous solutions Synthetic polymers can also be used, e g polyacrvlamides, polyacrvlates, polvamides and similar polymers Xanthan and succinoglycan polymers are particularly effective in this invention Fluid loss control agents are typically poiymers, for example starch, modified starches and/or deπvatised cellulose Crystallisation modifiers or inhibitors, e g phospnonates, polyacrvlates and other mateπals with similar effects can be included
Clay stabilisation additives include glycols. silicates and polyvinyl alcohol. The well fluids of the invention can be used in a variety of ways in oil and gas well operations. These include using calcium formate brine-based systems including finely divided panicles of calcium and/or magnesium formate as a weighting material. Such fluids can be made with relatively low densities and afford saturated systems which extend the range of fluids available. Also brine-based systems including finely divided particles of calcium and/or magnesium formate can be used in workover and completion methods in which the fluid is pumped down the well so that the solid particles are forced to bridge across the pore structure of the strata of the rock formation to block or seal the pores to enable operations to be carried out in the well whilst the rock formation is sealed from the weil and subsequently dissolving the formate paniculate solids by passing a sub-saturated brine into the well to dissolve the panicles of calcium and/or magnesium formate thus reopening the pores of the rock formation.
Accordingly, in a further aspect, the invention includes a method of conducting completion or workover operations on an oil or gas well by passing a well fluid into or through a permeable oil or gas-bearing rock stratum and which comprises: i pumping down the well to a position adjacent the oil or gas bearing stratum a weil fluid having dispersed therein finely divided particles of calcium and/or magnesium formate: ii applying pressure to the well fluid to force the panicles of calcium and/or magnesium formate to bridge across the pores of the permeable stratum to reduce the permeability of the stratum: iii conducting completion and/or workover operations on the weil; and iv subsequently removing the particles from the pores of the rock stratum by passing a well fluid which is undersaturated in respect of calcium and/or magnesium formate as appropriate over the stratum to dissolve the solid calcium and/or magnesium formate, thereby restoring the permeability of the stratum.
In particular in this aspect of the invention the well fluid comprises a saturated aqueous solution of an alkali or alkaline earth metal formate, especially calcium formate, having dispersed therein finely divided particles of calcium and/or magnesium formate, especially calcium formate.
The following Examples illustrate the invention All pans ana percentages are oy weignt unless otherwise stated
Sizeα calcium formate - is paniculate calcium formate having a particle size range of from 1 to 100 um
Calcium formate bnne - Base Bnne A - s a saturateα aqueous calcium formate solution containing 160 g 1 ' of calcium formate ana having a densitv of 1 1 g ml '
Sodium formate oπne - Base Bnne B - is a saturated aαueous soαium formate solution containing 355 g i of soαium formate ana having a αensity of 1 32 g ml '
Calcium Dromiαe/nitrate bnne - Base Bnne C - is a mixed sait bnne containing 609 g 1 ' caicium bromiαe ana 617 g 1 ' calcium nitrate and having a density of 1 8 g.mi '
Potassium formate Dπne - Base Bnne D - is a saturated aαueous potassium formate solution containing 1209 g i of potassium formate and having a density of 1 57 g.ml '
Caesium formate/ potassium formate - Base Bnne E - is a mixeα salt bnne containing 770 g l 1 of caesium formate and 604 g 1 ' potassium formate and having a density of
1 8 g ml '
Xanthan gum - is the αrv material obtained from Rhone Poulenc
Succmogiycan broth - is an aqueous broth of bacteπal Succinoglycan from Shell Chemicals having a concentration of about 10% w/v (ca. 100 g.l ') In the Examples, the amount used is given as the approximate amount of the dry poiymer
Modified starch (Mod. St.) - is a crossiinked etherified starch obtained from Chemstar Products Inc. of Minneapolis. USA.
.Modified Cellulose (Mod. Cell.) - is a purified low viscosity oil field grade of ( polyanionic carboxymethyl cellulose from Akzo Chemie.
Fluid Loss Control Test Method
The test method was carried out in a smail cylindrical steel pressure cell which can be sealed at both ends. The closures at both the base and the top of the cell include vaives.
The base of the ceil was sealed, a very fine mesh sieve inserted and a bed of fine sand was built up on the sieve. The sand bed simulates a permeable rock. The void volume of the sand be.: was flooded with an inert fluid, e.g.. with oil or an appropriate brine and the cell was heated in a specially designed heating jacket until it attained the desired test temperature. A well fluid to be tested was introduced into the cell above the sand bed (taking care not to disturb the surface of the bed), and the top closure of the cell was fitted.
The upper part of the cell was pressurised through the valve in the top closure. When the pressure and temperature reached the desired test values the valve in the base closure was opened thus applying a pressure differential across the sand bed. The pressure forced fluid into the sand bed which displaced the liquid which had been used to flood the pore volume of the sand bed. The voiu e of liquid displaced from the bed is a direct measure of the invasion of the bed by the fluid under test. A well fluid, with no fluid loss control properties runs straight through the cell and thus the lower the volume of fluid displaced the better the fluid loss control properties of the well fluid under test. The volume of fluid displaced was a quantitative measure of the fluid loss control properties of the weil fluid under test. .At the end of the test run the cell was disassembled and the depth of the filter cake containing solid particulate material from the well fluid was measured as a further indication of the effectiveness of fluid loss
control (the smaller the depth of the filter cake containing the solid paniculate material from the well fluid the more effective the fluid loss control).
Examples 1 to 6
The well fluids of Examples i to 6 were made from Base Brines A, B, C, D and E described above to each of which was added sized particulate calcium formate. The formulations of these well fluids are set out in Table 1 below. In Example 3 the succinoglycan was added as a broth (described above). The quantity given in Table 1 is the amount of (notionally) dry polymer; the water in the broth is not explicitly stated in Table 1 but does reduce the density of the fluid somewhat. The densities of the fluids were measured and the fluids were rested as described above The test results, indicating the volume of fluid displaced and the thickness of the bed of calcium formate formed on the sand bed are set out in Table 2 below.
The test conditions were:
Pressure across sand bed 250 psi (1 72 MPa) Temperature " 0°C Sand bed 40/100 mesh sand
(panicle size 150 to 420μm)
These experimental data indicate that all the Examples gave good fluid loss control, Examples 1 and 2 being particularly good.
By way of comparison, when examples 1 to 6 were repeated with fluids which did not contain sized calcium formate the fluid passed quickly through the sand bed indicating that in the absence of sized calcium formate the fluids had little or no fluid loss control properties.
In this example the fluid loss control properties of an oil-based fluid are exemplified. .An oil-based fluid was proαuceα as follows.
176 4 ml of oil grade DF1 (obtained from M.I. Drilling Fluids), 6.0 g Organophilic clay, grade VG-69 (obtained from M.I. Drilling Fluids) and 5 0 g Lime (Ca(OH), ) (obtained from BDH) were mixed on a Hamilton Beach mixer for 10 minutes.
To the fluid from Step 1 were aαded the following emulsifiers: 4 75 g EMI-257 j 1 5 g EMI-258 I ail obtained from M.I. Drilling Fluids 2.5 g E I-259 ; The fluid was mixed for 5 minutes on a Hamilton Beach mixer.
Step 3 To the fluid from step 2 there was added 52.3 ml of water and
84 7 mi of CaC bnne (density 1 35 g mi") (obtained from Brunner Mond Ltd). The fluid was mixed on the Hamiiton Beacn mixer for 10 minutes.
To the fluid from step 3 there was added
3.0 g of Asphaltene based fluid loss agent (obtained from M.I. Drilling Fluids) and the fluid was mixed for 5 minutes on the Hamilton Beach mixer.
Step 5 To the fluid from step 4 there was added
87.5 g of sized calcium formate and the fluid was then mixed on the Hamilton Beach mixer for a further 30 minutes.
Samples of the fluid were subjected to storage te.ts to examine the effect of storage on stability of the fluid and the particle size of the tine calcium formate. Fluid Loss Properties
The fluid loss propeπy test as described above was repeated except that the test was carried out at a temperature of 80°C and. prior to use in the test, the fluid was stored at 30°C for 17 days in order to allow for equilibration of the fluid.
30 minutes after opening of the valve in the base closure of the pressure test cell only 8 ml of fluid have passed through the sand bed indicating that the fluid has excellent fluid loss control properties. Particle Size Stability
A sample of fluid was stores in an enclosed vessei within an oven in which the temperature was cycled for over 60 hours between ambient and 80°C for a total of 6 cycles. This cycling mimics the temperature conditions encountered by a fluid as it circulates round a borehole which is being drilled. Also temperature cycling is very conducive to particle growth and would be expected to accelerate the inherent growth tendencies, if any, of the calcium formate particles.
After the storage period, the insoluble calcium formate particles were recovered and their size distribution was measured using a Malvem Particle Size Analyser. The results were compared with those for fresh sized caicium formate. The comparative results are shown below in Table 3.
Fresh ! Cycied j
1 caicium formate calcium formate i
% less than 5.2μm 1 1.96 1 1.72 ! 1 % less than 1 1.5μm 25.12 25.20 !
% less than 25.5μm 55.90 52.50 '
% less than 83.3μm 94 60 88.40
The data in table 3 show no significant difference. It is clear that the caicium formate panicles did not grow during the period of cvciine .