During directional drilling operation, in order to achieve the correct angle and direction when drilling through a soft formation, a plug of a non-conventional cement is set across the zone in order to achieve the desired course and target. The non-conventional cement is preferably blast furnace slag and a water base drilling fluid.
Second, contamination of Portland cement with the drilling fluid is highly probable due to the process used to place the cement plug in the borehole. A successive displacement process is used wherein the cement slurry is pumped down the drill string (or similar work string with an inner diameter substantially smaller than the diameter of the borehole). The slurry is then displaced out the bottom of the drill string into the annulus between the borehole and drill string by pumping a second (displacing) fluid down the drill string. This displacing fluid is typically drilling fluid.
The borehole is filled with drilling fluid and the cement slurry exiting the bottom of the drill string is traveling at a higher velocity than the fluid moving up the much larger annular space. Thus the cement slurry is "jetted" into the drilling fluid as its flow direction changes 180 degrees. Any chemical incompatibility between the drilling fluid and cement slurry may produce a gelled mass that inhibits effective displacement of the drilling fluid by the Portland cement slurry which can result in contamination of the entire cement volume.
Spacers are often used ahead of the Portland cement slurry to prevent contamination of the cement with the drilling fluid. These spacers are similar in composition to the drilling fluid. Clay and/or polymeric thickeners are used to viscosity the base fluid (usually water) in order to suspend weighting agents such as barites, hematites, or ilmenite. Emulsions of oil and water may also be used to provide viscosity for solids suspension. Often, surfactants and/or other solvents may be incorporated into the spacer to improve compatibility with the drilling fluid. Although more chemically compatible with the cement, spacer contamination of the cement slurry can occur and the effect on cement compressive strength is often similar to the effect of drilling fluid contamination.
Third, the cement must adhere to the borehole walls to prevent downward movement of the plug when weight is applied during the drilling operation. This adhesion is typically referred to as the shear bond strength of the cement. Coatings on the surfaces of the formation can reduce the shear bond of the cement. The borehole wall is typically coated with a drilling fluid filter cake which was deposited when the formation was penetrated by the initial drilling operation. This drilling fluid filter cake has low strength and may be sheared off the borehole wall by downward movement of the cement plug during drilling. Drilling may be aggravated by the thickness of the filter cake and any bypassed drilling fluid left in sections of the annulus. Also, any coating of the spacer along the borehole wall may reduce the shear bond strength between the borehole wall and the cement plug.
The density of many materials used for plugs is greater than the drilling fluid density. The primary reason for this is higher compressive strength and greater drilling resistance. For Portland cement plugs, lower water to cement ratios are required to provide greater strength. Greater strength often is used to offset the potential strength reduction due to contamination by the drilling fluid. The disadvantage of high density formulations is the possibility of the plug falling through the drilling fluid below the interval where the plug is desired. The density differential between the drilling fluid and Portland cement increases the probability that an unstable interface will result between the cement and drilling fluid. If the interface between fluids is unstable, cement and drilling fluid can mix causing a poor quality plug.
Accordingly, the present invention is directed to overcoming the above noted problems with Portland cement in the art, and in particular to problems experienced with effective directional drilling cement plugs in oil and gas wells.
SUMMARY OF THE INVENTION
It is the primary purpose of the present invention to provide a method for changing the direction of drilling of a wellbore, using a cement plug.
Accordingly, a method is provided for directionally drilling a well, comprising:
Preparing a cementitious slurry comprising:
(a) a cementitious component selected from blast furnace slag and a proton acceptor metal compound; and
(b) an activator wherein, when said cementitious component is said blast furnace slag, said activator is optionally an alkaline agent, and when cementitious component is said metal compound, said activator is a phosphorus acid or one of a polymer component of the formula: ##STR1## wherein A is ##STR2## or a mixture of ##STR3## and wherein R is H or a 1-10 carbon atom alkyl radial and the ratio of m to n is within the range of 0:1 to 100:1; and (c) a water source selected from water, brine, seawater, water base drilling fluid, and water emulsion drilling fluid;
displacing the slurry in the wellbore to a location therein where said direction of drilling is to be changed;
allowing the slurry to solidify and form a plug;
drilling a pilot hole in said plug in the desired new direction of drilling; and
continuing the direction of drilling of said well bore by way of said pilot hole in said cement plug.
Other purposes, distinctions over the art, advantages and features of the invention will be apparent to one skilled in the art upon review of the following.
DESCRIPTION OF PREFERRED EMBODIMENTS
The following preferred embodiments of the invention explain the principles of the invention.
The present invention provides a unique method devised to provide a directional drilling cement plugs in vertical, deviated, and horizontal wells. The invention centers around the solidification of non-conventional cement plugs preparatory to changing direction of drilling.
The present invention provides an improved process for plugging a section of an existing borehole with a non-conventional cement, the cement being resistant to drilling fluid contamination, having better adhesion to the filter cake along the borehole wall and being more compatible with the drilling fluid in the wellbore. The non-conventional cementitious slurry of this invention is more rheologically and chemically compatible with the drilling fluid than is a cement conventionally applied in forming directional drilling plugs. Thus, the invention encompasses embodiments in which no spacers are used ahead of the cementitious slurry to prevent commingling with the drilling fluid. In such embodiments, the non-conventional cementitious slurry is placed in direct contact with the drilling fluid, eliminating the need for problem-causing chemical spacers which are preferred for placement of Portland cement plugs, as discussed supra.
In the drilling of a well bore, it is often desirable or necessary to change the direction of the well bore. The angle of the well bore from vertical can be increased or decreased by adjusting drilling conditions, such as the weight exerted on the drill bit or the rotary speed of the drill bit; or special tools designed specifically to effect a change in well bore direction can be used.
Certain formations cause the drill bit to drill in a particular direction. If that direction is away from vertical in a vertical well, undesirable well bore deviation can result. In a directional well which is purposely drilled at an angle after drilling an initial portion of the well bore vertically, the direction induced by the formation can make following the desired path difficult. In those and other instances, special directional drilling tools are often used such as a whip-stock, a bent sub-downhole motorized drill combination, and the like. Generally, the directional drilling tool or tools used are orientated so that a pilot hole is produced at the desired angle to the previous well bore in a desired direction. When the pilot hole has been drilled for a short distance, the special tool or tools are removed, if required, and drilling along the new path is resumed.
In order to insure that the subsequent drilling follows the pilot hole, it is often necessary to drill the pilot hole in a cement plug placed in the well bore. That is, prior to drilling the pilot hole, a cement slurry is pumped into the well bore and allowed to set therein. The pilot hole is then drilled in the cement plug formed in the well bore, and the high strength of the cement plug insures that the subsequent drilling proceeds in the direction of the pilot hole. While this procedure is generally successful in insuring that the drilling follows the desired path, the cement slurries heretofore used lack strength and good bonding to the borehole.
Drilling of the borehole is preferably conducted with a universal fluid, which is a drilling fluid, containing the non-conventional cementitious slurry. This results in a settable filter cake being deposited on the borehole wall. The settable filter cake furnishes an excellent means for bonding the plug to the borehole in order to effectively seal the thief zone.
Cementing of the well is preferably conducted by adding the non-conventional slurry to the universal fluid. This results in a cement which readily bonds to the settable filler cake. Of course it is manifest that drilling and cementing may be conducted with conventional fluids known to the art which work well with the non-conventional cement plugs of this invention.
In this description the term `cementitious component` means either an hydraulic material which on contact with water and/or activators hardens or sets into a solidified composition or a component which, on contact with a reactive second component, sets or hardens into a solidified composition. Thus, broadly it can be viewed as a material which can chemically combine to form a cement. A slurry of the cementitious component and the component or components which cause it to harden is referred to herein as a cementitious slurry.
The initial drilling fluid or mud can be either a conventional drilling fluid, i.e., one not containing a cementitious component, or it can be one already containing a cementitious component in a relatively small amount. The drilling fluid can be either a water-based fluid or an oil-based fluid. The term `water-based fluid` is intended to encompass both fresh water muds, salt water containing muds, whether made from seawater or brine, and other muds having water as the continuous phase including oil-in-water emulsions. It is generally preferred that the water-based drilling fluids use water containing dissolved salts, particularly sodium chloride. In these instances, 0.1 to saturation sodium chloride may be used. One suitable source is to use seawater or a brine solution simulating seawater. Particularly in the embodiment using slag, the strength of the resulting cement is actually enhanced which is contrary to what would be expected in view of the intolerance of Portland cement to brine. Various salts, preferably organic salts, are suitable for use in the drilling fluid used in this invention in addition to, or instead of NaCl, including, but not limited to, NaBr, KCl, CaCl.sub.2, NaNO.sub.3, NaC.sub.2 H.sub.3 O.sub.2, KC.sub.2 H.sub.4 O.sub.2, NaCHO.sub.2 and KCHO.sub.2 among which sodium chloride is preferred, as noted above. The term `oil-based fluids` is meant to cover fluids having oil as the continuous phase, including low water content oil-base mud and invert oil-emulsion mud.
The term `universal fluid` is used herein to designate those compositions containing cementitious material, which compositions are suitable for use as a drilling fluid, and which compositions thereafter, for the purpose of practicing this invention, have additional cementitious material and/or activators such as accelerators (or reactive second components) added to give a cementitious slurry.
Thus, with the universal fluid embodiment of this invention, the purpose of one aspect of the invention is achieved through a method for drilling and cementing a well comprising preparing a universal fluid by mixing a drilling fluid and a cementitious material; drilling a borehole with the universal fluid and laying down a settable filter cake on the walls of the borehole during drilling of the well; diluting the drilling fluid; adding additional cementitious material and/or accelerators (or reactive second components) and introducing the thus-formed cementitious slurry into the wellbore and into an annulus between the wellbore and a casing where it hardens and sets up forming a good bond with the filter cake which filter cake, with time, actually hardens itself because of the presence of cementitious material therein. This hardening is facilitated by any accelerators which may be present in the cementitious slurry and which migrate by diffusion and/or filtration into the filter cake.
Non-Conventional Cements
The cementitious component can be any one or more of: conventional hydraulic cement, natural or artificial pozzolan, or the metal compound used to produce an ionomer or to produce a phosphorus salt. The preferred cementitious material is one selected from the group consisting of blast furnace slag, a metal oxide component used to produce the ionomer and a metal oxide component used to produce the phosphorus salt. By `blast furnace slag` is meant the hydraulic refuse from the melting of metals or reduction of ores in a furnace as disclosed in Hale and Cowan, U.S. Pat. No. 5,058,679 (Oct. 22, 1991), the disclosure of which is hereby incorporated by reference. By ,phosphorus salt, is meant a phosphonate, a phosphate or a polyphosphate as is described in detail hereinafter.
The preferred blast furnace slag used in this invention is a high glass content slag produced by quickly quenching a molten stream of slag at a temperature of between 1400.degree. C. and 1600.degree. C. through intimate contact with large volumes of water. Quenching converts the stream into a material in a glassy state having hydraulic properties. At this stage it is generally a granular material that can be easily ground to the desired degree of fineness. Silicon dioxides, aluminum oxides, iron oxides, calcium oxide, magnesium oxide, sodium oxide, potassium oxide, and sulphur are some of the chemical components in slags. Preferably, the blast furnace slag used in this invention has a particle size such that it exhibits a surface area between 500 cm.sup.2 /g and 15,000 cm.sup.2 /g and more preferably, between 3,000 cm.sup.2 /g and 15,000 cm.sup.2 /g, even more preferably, between 4,000 cm.sup.2 /g and 9,000 cm.sup.2 /g, most preferably between 4,000 cm.sup.2 /g and 8,500 cm.sup.2 /g. An available blast furnace slag which fulfills these requirements is marketed under the trade name "NEWCEM" by the Blue Circle Atlantic Company. This slag is obtained from the Bethlehem Steel Corporation blast furnace at Sparrow's Point, Md.
A usual blast furnace slag composition range in weight percent is: SiO.sub.2, 30-40; Al.sub.2 O.sub.3, 8-18; CaO, 35-50; MgO, 0-15; FeO, 0-1; S, 0-2 and Mn.sub.2 O.sub.3, 0-2. A typical specific example is: SiO.sub.2, 36.4; Al.sub.2 O.sub.3, 16.0; CaO, 43.3; MgO, 3.5; FeO, 0.3; S, 0.5; and MnO.sub.2 O.sub.3 <0.1.
Blast furnace slag having relatively small particle size is frequently desirable because of the greater strength it imparts in many instances to a final cement. Characterized in terms of particle size the term "fine" can be used to describe particles in the range of 4,000 to 7,000 cm.sup.2 /g. Corresponding to 16 to 3 microns in size; "microfine" can be used to describe those particles in the 7,000 to 10,000 cm.sup.2 /g range that correspond to particles of 5.5-16 microns in size and "ultrafine" can be used to describe particles over 10,000 cm.sup.2 /g that correspond to particles 5.5 microns and smaller in size.
However, it is very time consuming to grind blast furnace slag to these particles sizes. It is not possible to grind blast furnace slag in a manner where particles are entirely once size. Thus, any grinding operation will give a polydispersed particle size distribution. A plot of particle size versus percent of particles having that size would thus give a curve showing the particle size distribution.
In accordance with a preferred embodiment of this invention a blast furnace slag having a polydispersed particle size distribution exhibiting at least two nodes on a plot of particle size versus percent of particles in that size is utilized. It has been found that if only a portion of the particles are in the ultrafine category, the remaining, indeed the majority, of the slag can be ground more coarsely and still give essentially the same result as is obtained from the more expensive grinding of all of the blast furnace slag to an ultrafine state. Thus, a grinding process which will give at least 5% of its particles falling within a size range of 1.9 to 5.5 microns offers a particular advantage in economy and effectiveness. More preferably, 6 to 25wt% would fall within the 1.9 to 5.5 micron range. The most straightforward way of obtaining such a composition is simply to grind a minor portion of the blast furnace slag to an ultrafine condition and mix the resulting powder with slag ground under less severe conditions. Even with the less severe conditions there would be some particles within the fine, microfine or ultrafine range. Thus, only a minority, i.e., as little as 4wt% of the slag, would need to be ground to the ultrafine particle size Generally, 5 to 20wt%, more preferably 5 to 8wt% can be ground to the ultrafine particle size and the remainder ground in a normal way thus giving particles generally in a size range of greater than 11 microns, the majority being in the 11 to 31 micron range.
By ionomer is meant organometal compositions having a metal attached to or interlocking (crosslinking) a polymer chain. Suitable polymer components of such ionomers can be represented by the formula ##STR4## wherein A is ##STR5## or a mixture of ##STR6## and wherein R is H or a 1-10 carbon atom alkyl radical. The ratio of m to n is generally within the range of 0:1 to 100:1, preferably 0.1:1 to 10:1.
The polymers generally have a ratio of functional groups to polymer chain carbons within the range of 1:2 to 1:10, preferably about 1:3. Thus, if m and n are 1, R is H and A is carboxylate, there would be a ratio of carboxylic carbons (1) to polymer chain carbons (4) of 1:4. The polymer can also be a polycarboxylic acid polymer. One of the more preferred polymers is that made from partially hydrolyzed polyacrylamide. The hydrolysis can vary from 1% up to 100% and preferably from 10% to 50%, most preferably from 25% to 40%. The molecular weight of the polymers can vary widely so long as the polymers are either water-soluble or water-dispersable. The weight average molecular weights can range from 1000 to 1,000,000 but preferably will be in the range of 1,000 to 250,000, most preferably 10,000 to 100,000. Carboxylate polymer with a low ratio of COOH:C within the range of 1:3 to 2:5 are preferred. Especially preferred is a carboxylic acid polymer having a ratio of carboxylic carbons to polymer chain carbons (including carbons of pendant chains) of about 1:3 and a molecular weight within the range of 10,000 to 100,000. Partially hydrolyzed polyacrylamide polymers in the range of 5,000-15,000,000 molecular weight are suitable. The copolymers will generally have from 2-99, preferably 5-80, more preferably 10-60 mole percent acid-containing units.
The ionomers suitable for use in this invention are the water-insoluble reaction product of a proton acceptor metal compound which serves as the cementitious component and a carboxylic, sulfonic, or phosphonic acid polymer component. The metal compound generally is a metal oxide such as MgO or ZnO. The preferred metal oxides are magnesium oxide and zinc oxide, and most preferably, magnesium oxide. The applicable metal oxides are generally fired at temperatures above 1,000.degree. F for several hours to reduce chemical activity prior to grinding to final particle size for use in reacting with the acid component.
In instances where it is desired that the metal compound component add weight to the drilling fluid, the metal compound is preferably a water-insoluble metal compound with a specific gravity of at least 3.0, preferably 3.5. By `insoluble` is meant that less than 0.01 parts by weight dissolve in 100 parts by weight of cold (room temperature) water.
The poly(carboxylic acid) component can be any water soluble or water dispersable carboxylic acid polymer which will form ionomers. Ionomer forming polymers are well known in the art. Suitable polymers include poly(acrylic acid) poly(methacrylic acid), poly(ethacrylic acid), poly(fumaric acid), poly(maleic acid), poly(itaconic acid) and copolymers such as ethylene/acrylic acid copolymer and ethylene/methacrylic acid copolymer. The copolymers are generally random copolymers. An example of phosphonic acid polymers is poly(vinyl phosphonic acid) which is made from vinyl phosphonic acid, ##STR7## Suitable copolymers containing vinyl phosphonic acid include vinyl phosphonic acid/acrylic acid copolymer as well as copolymers with other unsaturated monomers, with or without a functional group.
In some instances, it is preferred to use water dispersable, as opposed to water soluble, polymers. Ideally, in such instances the melting point of the polymer should be higher than the placement temperature (circulating temperature) in the wellbore during the "cementing" operation and lower than the maximum, static temperature of the surrounding formations. It is desirable for the polymer to melt and react after placement as the temperature in the wellbore increases from the circulating temperature to the static temperature of the surrounding formations.
The amount of polymer utilized will vary widely depending upon the carboxylic acid content of the polymer; broadly, 10 to 200, preferably 10 to 100, most preferably 10 to 80wt%, based on the weight of metal compound, can be present. With the polymers having a low ratio of m to n, a smaller amount is required because of the higher functional group content of the polymer. Conversely, with the high ratio of m to n, an amount of polymer toward the higher end of the ranges is preferred. Polymers with ester groups will delay the setting of the cement where this is desired.
Phosphates and phosphonates, referred to herein as phosphorus salts, used in accordance with this invention also are produced from a two-component composition, the first component of which is a metal compound identical in scope to that used in the ionomers as described hereinabove so long as the resulting phosphorus salt is insoluble in water. Most preferred are MgO and Zno.
The second component is a phosphonic or phosphoric acid, preferably a polyphosphoric acid. The term `phosphoric acid` is meant to encompass both linear and cyclic polyphosphoric acids. These second component acids are referred to herein as phosphorus acids. Linear phosphoric acids can be depicted by the general formula H.sub.n+2 P.sub.n O.sub.3n+1 where n is 1-100, preferably 2 to 50, more preferably, 2 to 20. Examples include di-(pyro)phosphoric acid, tri-(tripoly)phosphoric acid, tetra-phosphoric acid and higher molecular weight polyphosphoric acids as well as phosphoric acid. Mixtures of acids, including those traditionally referred to as meta phosphoric acid, are particularly suitable for use in this invention.
The formation of one phosphate cement using a metal oxide as the metal compound can be depicted as follows: ##STR8## where: X is usually 4; and
MO=metal oxide which is amphoteric or is a proton acceptor.
With the ionomers, and the phosphorus salts when made with a polyvalent metal compound, a crosslinked network structure exists as a result of the addition of the second component, thus giving a very strong solid cement.
The particle size of the metal compound component can vary widely. Generally, it will be within the range such that the powder exhibits a surface area within the range of 500 cm.sup.2 /g to 30,000 cm.sup.2 /g, preferably 1,500 cm.sup.2 /g to 25,000 cm.sup.2 /g, most preferably 2,000 cm.sup.2 /g to 20,000 cm.sup.2 /g.
Because of the mass provided by the metal compound component of the ionomer or the polyphosphorus salt, these cementitious materials are generally actually heavier than most slag or Portland cement materials. In the embodiments using these cementitious materials this high density provides significant advantages in certain utilities. For one thing, a smaller amount of the material can be used and still achieve a final mud and ultimately cement of a desired density. Secondly, because of the high density, it is possible to operate without weighting agents such as barium sulfate or barite. They offer a further advantage in that they do not set up until the second component is added.
The metal compound of the ionomer or phosphorus salt can be used as the sole cementitious material or can be used in admixture with siliceous hydraulic materials such as the blast furnace slag or Portland cement. In one embodiment an hydraulic component such as slag can be used to give the metal ion component of the ionomer or phosphate to give, in effect, a mixture formed in situ.
Preferably, when the ionomer or phosphorus salt is utilized, the metal compound is added first and thereafter at such time as it is desired for the cement to be activated to set, the other component is added. In the case of the universal fluids, a portion of the total metal compound can be added to the drilling fluid, the remainder being added after dilution when the cementitious slurry is being formed. Boric acid, borate salts, and aluminates such as sodium aluminate will delay the setting of the phosphate cement. Amounts of 1 to 100% by weight of the retarder may be used, based on the weight of the phosphorus acid.
A typical mud formulation to which cementitious material may be added to form drilling fluid is as follows: 10-20 wt% salt (70,000-140,000 mg/l), 8-10 lbs/bbl bentonite, 4-6 lbs/bbl carboxymethylated starch (fluid loss preventor), sold under the trade name "BIOLOSE" by Milpark, 0.5-1 lbs/bbl partially hydrolyzed polyacrylamide (PHPA) which is a shale stabilizer, sold under the trade name "NEWDRIL" by Milpark, 1-1.25 lbs/bbl CMC sold under the trade name "MILPAC" by Milpark, 30-70 lbs/bbl drill solids, and 0-250 lbs/bbl barite.
The sequence for universal fluid in this embodiment of the invention is to prepare the drilling fluid containing a portion of the total metal compound to be utilized, carry out the drilling operation, dilute the fluid, add the remainder of the metal compound, and thereafter add the acid components and utilize the cement for its intended purpose such as cementing a casing.
In accordance with the invention that utilizes universal fluid, the fluid itself becomes a part of the final cement and thus, this portion of the drilling fluid does not need to be disposed of.
In all embodiments of the invention, additional cement can be made and used, in accordance with this invention, for remedial cementing.
The ionomer embodiments of this invention are of particular value for filling and sealing the annulus between a borehole wall and a casing, or between casings, particularly where some degree of ductility and/or tensile strength is desired. The ionomer has good adhesive properties to the borehole wall and casing and has greater elasticity than is obtained with siliceous hydraulic materials such as Portland cement. Thus, such cements are resistant to cracking under conditions of cyclic loading as are frequently encountered in a wellbore. For similar reasons the ionomer embodiment of the invention is beneficial in cementing liners and tieback casing strings which may otherwise leak due to changes in pressure and temperature in the well during production operations. Another area where the ductility of the ionomer cement is of special value is in slimhole wells where the annulus is smaller. Still yet another area where this ductility is important is in extended reach drilling. The term `extended reach` is intended to cover horizontal drilling and any other well drilling operations which are off-vertical a sufficient amount to cause the casing to be displaced by gravity toward one side of the borehole.
As noted hereinabove the initial drilling fluid ca be either a conventional drilling fluid or it can be a universal fluid which already has cementitious material therein.
Dilution
In all embodiments, the amount of dilution can vary widely depending on the desired application. Generally, the fluid will be diluted with from 5 to 200, preferably 5 to 100%, more preferably 5 to 50% volumes of liquid (water in the case of a water-based fluid) per volume of initial drilling fluid. In one particularly preferred embodiment, the dilution is such that on addition of the cementitious component (or in the case of the universal fluid addition of the remaining cementitious component) the final density will be within the range of 30% less to 70% more than the original density, preferably within the range of 15% less to 25% more, most preferably, essentially the same, i.e., varying by no more than .+-.5 wt%. This is particularly valuable in an operation where there is a narrow pressure window between the pressure needed to prevent blowout and the pressure which would rupture or fracture the formation through which drilling has taken place.
The dilution fluid can be the same or different from that used to make the drilling fluid in the first place. In the case of brine-containing fluids the dilution fluid will generally be brine also. This is of particular benefit in offshore drilling operations where fresh water is not readily available but brine is since seawater is a desirable brine.
Thus, as noted above, a significant improvement in the operating procedure is provided in accordance with this invention. This is because the density of the drilling fluid is frequently tailored to the characteristics of the formation through which the wellbore is being drilled. Thus, the density is chosen in the first place to be sufficient to avoid inflow into the wellbore because of formation pressure but is further chosen to be insufficient to rupture or fracture the borehole wall and force the fluid out into the formation. By utilizing the dilution and thereafter addition of the cementitious component (or in the case of universal fluid, the remainder of the cementitious component) the cementitious slurry can likewise have a density tailored to the particular operation. In addition, this avoids undue thickening of the drilling fluid as would occur, particularly with some hydraulic components, without the dilution and thus the rheological properties of the cementitious slurry and the drilling fluid can both be tailored for optimum performance.
The invention (dilution of a drilling fluid and thereafter adding cementitious material to produce a cementitious slurry) offers special advantages with certain cementitious components in addition to the general benefits such as reduced equipment needs. With Portland cement it avoids the extraordinary viscosity increase that adding such an hydraulic material to a drilling fluid would give. With slag, organometals and polyphosphates there is the advantage that the cementitious component has a drilling fluid function. With the ionomers and polyphosphates there is the further general advantage that unlimited time can elapse between the drilling and cementing operations with no loss of properties of either because these materials do not begin to set until the second component is added.
The dilution can be carried out in either of two ways. First, a vessel containing drilling fluid can simply be isolated and the desired amount of water or other diluent added thereto. In a preferred embodiment, however, the drilling fluid is passed to a mixing zone as a flowing stream and the dilution fluid added "on the fly" to the flowing stream. Thereafter, the additional blast furnace slag is added. This avoids highly viscous cementitious slurry compositions and allows all of the pumping to be done with piping and pumps associated with the well rig without the need for pumps designed for pumping cement. This is of particular value in the areas to which this invention is of special utility, offshore drilling rigs where the transportation of additional pumping equipment is particularly inconvenient. Thus, it is possible to tailor the final density of the cementitious slurry, if desired, to a value within the range of 30% less to 70% more than the original density of the drilling fluid, preferably within the range of 15% less to 50% more, most preferably essentially the same, i.e., varying by no more than .+-.5 weight percent.
Mixed metal hydroxides can be used in the drilling fluid to impart thixotropic properties. The mixed metal hydroxides provide better solids suspension. This, in combination with the settable filter cake provided in the technique of this invention, greatly enhances the cementing in a restricted annulus. The mixed metal hydroxides are particularly effective in muds containing clay such as sodium bentonite. Preferred systems thickened in this way contain from 1-20 lbs/bbl of clay such as bentonite, preferably 2 to 15 lbs/bbl, most preferably 7 to 12 lbs/bbl. The mixed metal hydroxides are generally present in an amount within the range of 0.1 to 2 lbs/bbl of total drilling fluid, preferably 0.1 to 1.5 lbs/bbl, most preferably 0.7 to 1.2 lbs/bbl. Mixed metal hydroxides are known in the art and are trivalent metal hydroxide-containing compositions such as MgAl(OH).sub.4.7 Cl.sub.0.3. They conform essentially to the formula
Li.sub.m D.sub.d T(OH).sub.(m+2d+3+na) A'.sub.a n
where
M represents the number of Li ions present; the said amount being in the range of zero to about 1;
D represents divalent metals ions; with
d representing the amount of D ions in the range of zero to about 4;
T represents trivalent metal ions;
A' represents monovalent or polyvalent anions of valence -n, other than OH.sup.--, with a being the amount of A' anions; and
where (m+2d+3+na) is equal to or greater than 3.
A more detailed description can be found in Burba, U.S. Pat. No. 4,664,843 (May 12, 1987). The mixed metal hydroxides in the drilling fluid, in combination with blast furnace slag, tend to set to a cement having considerable strength in a comparatively short time, i.e., about one-half hour at temperatures as low as 100.degree. F. This can be a major asset in some applications. In such instances, a thinner such as a lignosulfate is preferably added before adding slag. However, one of the advantages of this invention is that it reduces or eliminates the need for additives to control free water or solids suspension. The activator or activators can be added either with any other ingredients that are added before the additional blast furnace slag, with the additional blast furnace slag, or after the addition of the additional blast furnace slag.
In some instances, it may be desirable to use a material which functions as a retarder along with the activator because of the need for other effects brought about by the retarder. For instance, a chromium lignosulfonate may be used as a thinner along with the activator even though it also functions as a retarder.
Other suitable thinners include chrome-free lignosulfonate, lignite, sulfonated lignite, sulfonated styrene maleic-anhydride, sulfomethylated humic acid, naphthalene sulfonate, a blend of polyacrylate and polymethacrylate, an acrylamideacrylic acid copolymer, a phenol sulfonate, a naphthalene sulfonate, dodecylbenzene sulfonate, and mixtures thereof.
In one embodiment the drilling fluid consists essentially of slag and seawater and is pumped exclusively using the piping and pumps associated with the drilling rig without the need for any pumps designed for pumping cement.
In the case of hydraulic materials, particularly the more preferred hydraulic material, blast furnace slag, the amount of hydraulic material present in the universal fluid is generally within the range of 1 to 100 lbs/bbl of final drilling fluid, preferably 10 to 80 lbs/bbl, most preferably 20 to 50 lbs/bbl. In the case of the organometals (ionomers) or phosphorus salts the amount of metal compound initially present in universal fluid can also vary widely. Generally, 1 to 500 lbs/bbl, preferably 50 to 300 lbs/bbl, most preferably 100 to 250 lbs/bbl of the metal compound are used.
The total amount of cementitious material in the cementitious slurry will typically range from about 20 lbs/bbl to about 600 lbs/bbl, preferably 100 lbs/bbl to 500 lbs/bbl, most preferably 150 lbs/bbl to 350 lbs/bbl. This can be adjusted to give the desired density as noted hereinabove.
Reference herein to additives encompasses both the specialized additives necessary for this invention such as the carboxylic acid polymer in the case of the ionomer or the polyphosphoric acid in the case of the polyphosphate as well as conventional additives.
Conventional Drilling Fluid Additives
Suitable fluid loss additives found in drilling fluids include bentonite clay, carboxymethylated starches, starches, carboxymethyl cellulose, synthetic resins such as "POLYDRILL" by SKW Chemicals, sulfonated lignite, lignites, lignin, or tannin compounds. Weight materials include barite, calcium carbonate, hematite and MgO, for example. Shale stabilizers that are used in drilling fluids include hydrolyzed polyacrylonitrile, partially hydrolyzed polyacrylamide, salts including NaCl, KCl, sodium or potassium formate, sodium or potassium acetate, polyethers and polycyclic and/or polyalcohols. Viscosifying additives can be used such as biopolymers, starches, attapulgite and sepiolite. Additives are also used to reduce torque. Suitable thinners such as chrome and chrome free lignosulfonates, sulfonated styrene maleic-anhydride and polyacrylate may also be used depending upon the mud type and mud weight. Lubricating additives include nonionic detergents and oil (diesel, mineral oil, vegetable oil, synthetic oil), for instance. Alkalinity control can be obtained with KOH, NaOH or CaO, for instance. In addition, other additives such as corrosion inhibitors, nut hulls etc. may be found in a typical drilling fluid. Of course, drill solids including such minerals as quartz and clay minerals (smectite, illite, chlorite, kaolinite, etc.) may be found in a typical mud.
It is particularly desirable in accordance with a further embodiment of this invention to utilize silica to increase the temperature resistance of the final cement. The use of blast furnace slag as the hydraulic component, in itself, allows greater latitude in the temperature which can be tolerated, because the blast furnace slag is inherently less thermally sensitive than other known hydraulic components such as Portland cement and thus can be hardened over a wider range of temperatures without resort to additives. This is of particular advantage where there is a substantial temperature gradient from the top to the bottom of a borehole section to be cemented. However, with the addition of silica, further temperature resistance may be imparted to the cement after it is set. Thus, with blast furnace slag and silica a temperature resistant cement is possible and with other cementitious components the temperature range can be extended through the used silica. Suitable silicas include crystalline silicas such as alpha quartz.
Universal Fluids
In another embodiment of this invention, most or all of the components of the drilling fluid are chosen such that they have a function in the cementitious material also. The following Table illustrates the uniqueness of such formulations.
TABLE A
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Function
Drilling Fluid Cementitious Slurry
Additive
Primary Secondary Primary Secondary
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Synthetic
Fluid loss Fluid loss
Retarder
polymer.sup.1
control control
Starch.sup.2
Fluid loss Viscosity Fluid loss
Retarder
control control
Bio- Viscosity Viscosity
Retarder
polymer.sup.3
Silicate
Viscosity Shale Accelerator
--
stabilizer
Carbo- Deflocculant
-- Retarder Defloccu-
hydrate lant
polymer.sup.4
Barite.sup.5
Density -- Density Solids
concentration
Benton-
Fluid loss -- Fluid loss
Solids
ite.sup.6
control control concentr.
Clay/ -- -- Solids --
Quartz concentration
dust.sup.7
Slag.sup.8
Cuttings -- Cementitious
Solids
stabilizer concentration
Lime.sup.9
Cuttings/ Alkalinity
Accelerator
Solids
Wellbore concentration
stabilizer
PECP.sup.10
Shale Fluid loss
Retarder Rheologi-
stabilizer cal
Control
NaCl Shale -- -- --
stabilizer
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.sup.1 Polydrill, A synthetic polymer manufactured by SKW Chemicals Inc.
under trade name Polydrill, for instance
.sup.2 Starch made by Milpark Inc. under the trade name "PERMALOSE", for
instance.
.sup.3 A biopolymer made by Kelco Oil Field Group, Inc., under the trade
name "BIOZAN" for instance.
.sup.4 Watersoluble carbohydrate polymer manufactured by Grain Processing
Co. under trade name "MORREX".
.sup.5 Barite is BaSO.sub.4, a drilling fluid weighting agent.
.sup.6 Bentonite is clay or colloidal clay thickening agent.
.sup.7 Clay/quartz solid dust manufactured by MilWhite Corp. under the
trade name "REVDUST", for instance.
.sup.8 Blast furnace slag manufactured by Blue Circle Cement Co. under th
trade name "NEWCEM" is suitable.
.sup.9 CaO
.sup.10 Polycyclicpolyetherpolyol
The material in the above Table A labeled PECP is of special significance in connection with this invention. This refers to a polyhydric alcohol most preferably a polycyclicpolyetherpolyol. A general chemical composition formula representative of one class of these materials is as follows: ##STR9## where x.gtoreq.1 and y.gtoreq.0.
A more complete description of these polycyclicpolyetherpolyols is found in the Hale and Cowan patent, U.S. Pat. No. 5,058,679 (Oct. 22, 1991), referred to hereinabove, the disclosure of which is incorporated herein by reference.
Universal drilling fluids which utilize blast furnace slag can be subsequently activated to cause the drilling fluid to develop compressive strength with time.
Suitable activators include sodium silicate, sodium fluoride, sodium silicofluoride, magnesium silicofluoride, magnesium hydroxide, magnesium oxide, zinc silicofluoride, zinc oxide, zinc carbonate, titanium carbonate, sodium carbonate, potassium sulfate, potassium nitrate, potassium nitrite, potassium carbonate, sodium hydroxide, potassium hydroxide, copper sulfate, lithium hydroxide, lithium carbonate, calcium oxide, calcium sulfate, calcium nitrate, calcium nitrite, calcium hydroxide, sodium sulfate and mixtures thereof. A mixture of caustic soda (sodium hydroxide) and soda ash (sodium carbonate) is preferred because of the effectiveness and ready availability. When mixtures of alkaline agents such as caustic soda and soda ash are used the ratio can vary rather widely since each will function as an accelerator alone. Preferably, about 1 to 20 lbs/bbl of caustic soda, more preferably 2 to 6 lbs/bbl of caustic soda are used in conjunction with from 2 to 50 lbs/bbl, preferably 2 to 20 lbs/bbl of soda ash. The references to "lbs/bbl" means pounds per barrel of final cementitious slurry.
A combination of sodium hydroxide and sodium carbonate is preferred. In addition, blast furnace slag can be added between the use of this material as a drilling fluid and its use as a cement. The additional slag can be the activator, especially if heat is imparted to the operation. Each component is an important ingredient for both the drilling fluid and the cement. The PECP is particularly significant in combination with slag since it acts as a retarder and thus provides significant drilling fluid functions in general and specific drilling functions relative to the slag component as well as significant cement functions. PECP also reduces the friction coefficient of muds on casing and filter cake, and pullout forces required to release stuck pipe are dramatically reduced with PECP
