Chapter 35
A Unique Source of Potassium for Drilling and Other Well Fluids 1
2
John T. Patton and W. T. Corley
1Department of Chemical Engineering, New Mexico State University, Las Cruces, NM 88003 Mayco Wellchem, Inc., 1525 North Post Oak Road, Houston, TX 77055 2
Laboratory andfieldtests of a clear well fluid, formulated with tetrapotassium pyrophosphate, TKPP, indicate increased pro ductivity from inhibition of clay swelling, sloughing and disper sion. Adding small amounts of multivalent cations to T K P P fluids further suppresses clay-water interactions. T K P P com pletionfluidscan be converted to superior drillingfluidsby viscosifing with xanthan gum. Handling characteristics of T K P P solutions are superior to most other well fluids. They are not acidic, nontoxic and non-corrosive, a definite benefit for both rig personnel and the environment. They are compatible with most formation fluids, but will precipitate when mixed with spent acid. Unlike well fluids containing zinc and calcium, pH can be adjusted. T K P P is available to petroleum operators worldwide as free-flowing powder or a 60% wt. solution. Since the invention of rotary rigs, used for drilling oil and gas wells, scientists have been searching forfluidsthat will both facilitate the drilling process and provide maximum productivity once the well is completed. There are two prime requisites for all well fluids. These are: (1) They must perform their required functions in a superior manner; e.g., completion fluids must balance the formation pressure and, thus, avoid the possible loss of the well due to blow-out. Drilling fluids should minimize the cost of making hole. (2) Filtrate lost to the formation or particulates deposited in oil flow pas sages must not impair a well'sflowpotential when the well is returned to operation. The most sensitive test for identifying damage characteristic of a well fluid involvesflowingthe well fluid through a reservoir core. Forfluidscontain ing particulates, it is necessary to test both the whole fluid and the filtrate 0097-6156/89/0396-0621$06.00/0 o 1989 American Chemical Society
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in order to assess the total damage potential and identify the mechanisms responsible. Clay minerals, inevitably present in a petroleum formation, are sensitive to the type and concentration of ions contained in the well fluid filtrate lost to the reservoir. This sensitivity is demonstrated by a reduction in the permeability caused by the well fluid filtrate flowing through the core under investigation. Clays have the capacity to exchange ions with well fluids. When calcium ions, incorporated in the clay matrix, are exchanged for sodium or even potassium ions, clays can swell and/or become dispersed in the fluid. This mechanism significantly reduces permeability, i.e., causes large productivity damage^ ' '. The equilibrium concentration of the various ions strongly favors the adsorption of multivalent ions by the clay minerals. For this reason, it is possible to counteract the swelling effect of well fluids on clays by the addition of small amounts of polyvalent ions. Calcium is by far the most effective, but the least soluble in the presence of other salts. Magnesium has been found to be advantageous and also synergistic when used in conjunction with calcium ions. Fluids containing divalent ions usually cause less permeability damage in petroleum reservoir cores. A second cause of reduced productivity is mechanical blockage. When the well fluid contains particulates, damage occurs when the solids become tightly wedged in the tiny interstices through which oil flows. This damage, which can be so severe as to render a well uneconomic, has prompted many investigators to regard particulate blocking as the prime cause of productivity impairment^ ' !. The now popular "clear" well fluids were introduced to avoid particulate damage. These fluids are often viscosified to minimize leak-offt !. Both field and laboratory results indicate that formation damage can only be minimized through the selection of well fluids whose chemical composition is formulated to avoid both fluid and particulate damage. This objective has been difficult if not impossible to achieve with current well fluid additives. Recognition of the chemistry required to formulate such a nondamaging well fluid is not in itself sufficient to prevent damage. Kruger has observed that strict quality control of a fluid's physical and chemical properties, especially during the completion process, is essential. In addition, damage can be further minimized through the use of clean pipe and continuous circulation and filtration of the fluid being used in the well operation^. What has long been sought and badly needed is a soluble weighting agent less corrosive than, and equally non-damaging as, the popular calcium and zinc halides. Preliminary laboratory and field data indicate T K P P may be the solution. Work by Jones identified the desirability of incorporating T K P P as a scale inhibitor for packer fluids^. Subsequent work by Siskorski identified T K P P ' s superior properties in a blend for preparing high density, clear well fluids^. T K P P has long been recognized as a builder for liquid detergents. The fact that detergency is not a requisite property of a superior well fluid probably obscured excellent petroleum applications until now. This paper 1 2
3 4
5
35. PATTONANDCORLEY
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addresses the opportunities that exist for preparing improved well fluids, especially for wide application in drilling, based on T K P P . GENERAL:
T K P P ( K 4 P 2 O 7 ) is a merchant chemical produced by many major companies throughout the world. It is available commercially as a free flowing, white, grEr.ular solid or as a 60% wt. solution. In addition to its widespread use in ohe liquid detergent formulations, T K P P is also utilized in the food industry. It has been certified by the U . S. Department of Transportation as nontoxic. The solubility of T K P P in water at 60°F is shown in Table I. It is possible to achieve increased density at temperatures above 60° F because of increased solubility. T a b l e I. C o n c e n t r a t i o n - D e n s i t y o f T K P P S o l u t i o n s
Density lb/gal @ 16° C 9.0 9.6 10.7 12.0 14.0 15.2 (Solubility limit)
TKPP
Concentration
Wt %
lb/bbl
8.7 16 28 41 57 66
33 64 126 206 335 422
D A M A G E ASSESSMENT; C O R E TESTS:
Tests were run to compare conventional completion fluids, i.e., those containing calcium, zinc, and potassium salts. Each well fluid was passed through a five micron filter and then flowed through a fresh Berea sandstone core having a brine permeability of approximately 800 md. Prior to testing a well fluid, the core's initial permeability had been established by flowing a filtered reservoir brine through the core. The damage imparted by a filtered well fluid was determined by noting the decrease effected in the core's permeability compared to its initial permeability. The results, shown in Table II, quantify the adverse effect of common well fluid ions on permeability. Especially relevant are the data indicating that even calcium chloride/calcium bromide fluids cause some permeability reduction, although the cause of the adverse interaction is obscure. W i t h the exception of saturated zinc bromide, all of the fluids tested minimized permeability damage relative to fresh water which reduced permeability an average of 54% for three cores.
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OIL-FIELD CHEMISTRY
Table II. Formation Damage Effected by Clear Well Fluids Fluid Type
K
TKPP + TKPP TKPP+ CaCl /CaBr KC1 TKPP CaCl /CaBr KC1 KC1 ZnBr 2
2
2
3.8 3.8 11.3 2
2
Ion Cone, wt. % Ca Mg Zn
Core Perm., md Damage Init. Final %
.04
.41
-
-
874 837 874 711 794 837 855 794 794 673
-
.04 .16
1.6 11.3
-
-
.10
5.2 11.3
-
-
-
.41
-
.22
844 718 738 583 625 580 581 531 381 34
3 14 16 18 22 32 32 33 52 95
Although potassium chloridefluidsperformed better than the calcium and zinc halides, damage was still measurable. These results, confirmed in triplicate, were unexpected since it is well accepted that even 0.5 weight % KC1 sjiould protect Berea cores against permeability damage. The most plausible explanation lies in variation between the test procedures. The formation brine used to establish the core's initial permeability contained 2.7% total dissolved solids, TDS, with a monovalent-divalent (cal cium) ratio of 30. Once a core is equilibrated with this brine, any increase in the ratio or drastic decrease in TDS has the potential for decreasing perme ability. Obviously fresh water represents a significant decrease in TDS and, hence, the 54% permeability damage. Adding KC1 helps overcome the de creased salinity but, in so doing, increases the ionic ratio resulting in still measureable but usually reduced permeability damage. Even very small amounts of calcium provide a desirable decrease in the Na/Ca ratio. Prior studies indicating potassium chloride totally negates permeability reduction may have utilized water that contained some small amount of calcium ion to measure KC1 solution permeability. A second factor, which might explain the lack of K G damage reported in prior studies is a low ionic concentration, especially calcium, in the water used to equilibrate the cores prior to the K G tests. Increasing K G concentration lowers inhibition as shown in Table II. The fact that damage increased with K G concentration is consistant with the ionic ratio hypothesis and suggests a base exchange mechanism whereby calcium ions are more easily extracted from the clay and replaced by potassium ions as the potassium concentration increases. Similar tests were performed with 10% and 20% by weight aqueous so lutions of T K P P having approximately the same potassium ion concentration
35. PATTONANDCORLEY
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as the KC1 tests. Damage, although measurable, was reduced, indicating for the first time that an anion, in this case pyrophosphate, can contribute to reducing permeability damage. The damage potential of T K P P fluids was further reduced by the addition of multivalent cations. When these salts were added at approximately their solubility limit in T K P P solutions, damage decreased, lending additional credence to the observation that the addition potassium ions alone is not sufficient to completely eliminate formation damage. The severe interaction of the zinc bromide fluid, 19.2 ppg (2.32 g/cc), was unexpected. Severe plugging of the core occurred, caused by precipitation of zinc hydroxide, as the injected solution mixed with and was neutralized by formation brine. Tests in which the zinc bromide fluid was simply titrated with distilled water also produced a precipitate, 0.0036 g/cc. Titration in the presence of the common reservoir clay, montmorillonite, increased both the rate of precipitation, and total quantity to 0.03 g/cc. At the conclusion of a few selected damage tests, an additional experiment was performed in which solutions containing 10% T K P P , 0.1% calcium chloride, and 0.4% magnesium chloride were pumped through the damaged cores. In each instance, the permeability of the core recovered dramatically, as shown in Figure 1.
D A M A G E ASSESSMENT; CLAY SWELLING: Tests were conducted to determine the effect of T K P P solutions on the hydration and dispersion tendencies of clay particles. The test involved immersing a standard bentonite Volclay pellet in the solutions of T K P P and observing the degree of disintegration as a function of time. Comparable tests were also conducted using fresh water, halide completion fluids, and diesel oil for comparative purposes. T K P P solutions having densities ranging from ten to fifteen pounds per gallon, ppg, were tested to define the effect of T K P P concentration on clay inhibition. These tests indicate that T K P P , when used at higher solution densities, can inhibit the hydration and disintegration of watersensitive clays almost completely. When used in conjunction with polyvalent cations, inhibition is evident at concentrations as low as 75 ppb (0.21 g/cc). Even at this low concentration the inhibitive character of the fluid is much superior to that of the calcium bromide and zinc bromide clear completion fluids. This can be seen from the data shown in Table III.
626
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35. PATTON AND CORLEY
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T a b l e III. C l a y D i s i n t e g r a t i o n D u e t o F l u i d Interaction
Disintegration State of Volclay Tablet Conventional Tetrapotassium Pyrophosphate
Time, Well Fluid Minutes Properties Salt Type +
K , ppm. Density, ppg. 0.5 1.0 5.0 10.0 14.0 18.0 30.0 1 - No Visible Effect
CaBr 0 14.2
2
2 3 3 3 3 3 3
ZnBr i K C 1
TKPP* TKPP*
TKPP*
0 127,000 19.2 9.7
81,000 128,400 10.6 9.7
176,000 11.6
:
2 2 3 3 3 3 3
2 2 3 3 3 3 3
2 - Cracks/Sloughing
1 1 2 2 3 3 3
1 1 1 1 1 1 2
3 - Complete Disintegration
* T K P P solutions contain 0.21% C a C l and 0.65% M g C l 2
1 1 2 2 2 3 3
2
At solution densities of 13 ppg and above, the T K P P virtually eliminates any hydration and disintegration effects an aqueous fluid might have on water-sensitive clays. In this concentration range, the results of T K P P plus polyvalent cations are comparable to those obtained with a non-aqueous fluid such as diesel oil. However, as evidenced by the permeability regain effects noted in damaged sandstone cores, T K P P solutions invading the producing formation adjacent to the well bore might have the capacity to actually remove damage whereas the diesel oil has no ability to restore permeability in a similar manner. If so, the responsible mechanism would be the dehydration and subsequent shrinking of clays by the highly structured, concentrated T K P P solution. T K P P IN DRILLING FLUIDS:
The long-recognized ability of potassium ions to minimize the swelling and disintegration of water-sensitive clays would infer that T K P P should be a desireable additive for drilling fluids^. Current practice is to formulate drilling fluids with KC1 or K O H to supply the required potassium ion concentration. However, both chemicals generate problems that are often expensive to overcome. Potassium hydroxide is little used because of the high p H (above 12.0) and loss of desirable mud properties when enough is added to supply the requisite amount of potassium ion. It is good practice to avoid pH's above 11.5
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because of danger to rig crews, increased problems in controlling shale sloughing or clay swelling and difficulty in maintaining acceptable mud rheology. Therefore, the use of K O H is generally limited to p H control for KC1 muds. There are two major problems associated with adding KC1 to a drilling fluid. First, the corrosivity of the fluid is increased, often several fold^ ^ The increased corrosion of drill pipe, drill collars, bits, and pumps can be a significant expense. 10
Of even more economic importance is the rheological impact of the addition of KC1 to conventional water-base drilling fluids. KC1 causes undesirable increases in both yield point and gel strength that can only be eliminated by chemical disperants or by dilution with fresh water. Dilution in turn requires more KC1 for clay inhibition, and the cycle continues with mud costs escalating exponentially. Tests were conducted to compare the effect of KC1 and T K P P on the rheology of an unweighted (nondispersed) and a weighted (dispersed) drilling fluid. A l l fluids were mixed in an industry standard Hamilton Beach mixer. The rheology of each fluid was then measured in a Fann viscometer at 120°F at 300 rpm and 600 rpm. The results of these tests and the fluid formulations are shown in Table IV. The adverse effect on fluid rheology of adding potassium, KC1, Test B , and T K P P , Test C, is evident. Both salts cause increases in yield point, Y P , and initial gel strength. T K P P produced only about half as much increase as did KC1 and can be added in much higher concentrations before the rheological properties of the drilling mud become unacceptable. Similar results were obtained with a barite-weighted, dispersed drilling mud. The base fluid, Test D , has acceptable rheology; however, the addition of only 10 ppb of KC1, Test E , elelvated the yield point and initial gel to unacceptable levels. Although the addition of T K P P , Test F , caused increases in both Y P and gel, they were only about 7 5 % as great, as increases caused by KC1. This reduced adverse effect translates into a significant reduction in mud costs, as detailed in the results of actual drilling in experimental wells. The decrease in plastic viscosity for the weighted system, Test F , is beneficial. It indicates an increased pseudoplasticity that, in practice, will provide better hole cleaning and more horsepower available at the bit during drilling operations. When suitably viscosified, T K P P solutions become superior low solids drilling fluids. Many water-soluble polymers were tested to identify satisfactory viscosifiers. Most commercially available polymers were found to be insoluble in T K P P solutions at densities above 11 ppg. Only xanthan gum
Source ofPotassium for Drilling
35. PATTONANDCORLEY
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Table IV. Effect of Potassium Salts on Conventional Drilling Muds Composition/Property
A
B
C
D
E
F
Gel 15 Drill Solids 30 Chrome lignosulfonates 0
15 30 0
15 30 0
15 30 6
15 30 6
15 30 6
K Lignite
0
0
0
3
3
3
0 0 0 9.0
0 11 0 9.0
0 0 11 9.0
216 0 0 12.0
216 10 0 12.0
216 0 10 12.0
7
4
5
17
17
15
6
23
11
4
54
39
6
2
42
30
Concentration, ppb
Barite KCl TKPP Weight, ppg Plastic Vis., cp Y P , lbs/100 ft
2
Initial Gel lbs/100 ft
2
2
10
exhibited enough solubility to be useful in viscosifying T K P P solutions up to 14.5 ppg. This common drilling polymer is available in both powder and liquid form in the oil field. Its use is well known and does not require any special techniques or mixing equipment. A series of T K P P solutions were prepared; varying in weight from 10 to 12 ppg, these were viscosified with 2 ppb of Kelzan X C , a commercial xanthan drilling product. The rheological properties were measured at 1 2 0 ° F using a standard Fann Viscometer. Table V summarizes the rheological properties of the solutions so prepared. It was found that hydration of xanthan is retarded by high concentrations of T K P P . When preparing solutions having a density above 12 ppg, it is advisable to hydrate the xanthan in relatively fresh water first. After the xanthan is completed hydrated, granular T K P P can be added to achieve the desired solution density. The presence of the xanthan does not retard the rapid dissolution of the T K P P .
Table V . Rheology of T K P P - Xanthan Drilling Muds T K P P Cone.
Density
Apparent
ppb
Wt%
PPK
g/cc
V i s e , cp
0 86 145 206
0 20 31 41
8.33 10 11 12
1.00 1.20 1.32 1.44
15.5 26.5 31 42.5
Plastic V i s e , cp 6 7 10 19
Yield Point lb/100 F t . 19 23 26 33
2
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OIL-FIELD CHEMISTRY
There may be instances where a high concentration of T K P P is required to inhibit clay hydration, but a lower density or higher lubricity is desired. This can be achieved by emulsifying diesel or mineral oil in a T K P P solution viscosified with xanthan. Emulsion of oil in T K P P solutions can be achieved with a viscosifier such as xanthan alone although it is usually desirabale to add a surfactant to improve stability. Many different surfactant structures were tested for suitability as an emulsifying agent for oil in T K P P solutions. The best additive identified is a phosphate ester surfactant, Pluradyne O F 90, manufactured by B A S F Wyandotte. This material has been tested in the past for improving producing well productivity by reversing clay swelling and mitigating paraffin deposition problems. A T K P P solution having a density of 12 ppg was formulated by dissolving 1.5g of Kelco's KOD-85, a finely ground commercial xanthan gum product, in 299 cc tap water by mixing at high speed for 5 minutes in a standard Hamilton Beach mud mixer. 206 g of T K P P , followed by 18 m l of diesel oil, was then added and the viscosified solution blended for an additional 5 minutes with a Hamilton Beach mixer. A smooth, water-continuos emulsion formed immediately that contained a small amount of entrained air. One percent of B A S F Pluradyne OF-90 was added to the emulusion and blended for an additional 5 minutes. The resulting fluid was a smooth, creamy, drilling fluid containing finely dispersed air bubbles which broke out slowly. After standing overnight, the fluid was a homogeneous, water-containing emulsion containing no entrained air. Fluid rheology measured at room temperature in a Fann Viscometer, produced the following results: Apparent vis.=18.5 cp, Plastic vis.=13.0 cp, Yield p o i n t = l l lb/100 ft. These values are characteristic of a superior, low-solids, drilling fluid that promotes a high drilling rate and good solids removal. In addition, maximum inhibition of hydrating clays is provided.
2
DRILLING FIELD TEST Two wells were drilled in Frio County, Texas, using T K P P for clay/shale inhibition. They were compared to three wells that had just been finished in the same field, to the same depths, using the same rig and crews; all three using a KCl/polymer drilling fluid. The KC1 polymer wells experienced numerous hole problems including balling, stuck pipe, poor hole cleaning (gel sweeps were necessary), high torque, drag, and washout. The average mud cost for these KC1 polymer wells was $45,276. Two wells, drilled using T K P P and polymer, experienced no hole problems. The average mud cost for the two wells was $13,952, a 69% cost reduction in mud alone. Dollar savings on rig time were even more significant. The new additive was used on six wells in
35. PATTONANDCORLEY
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Lavaca County, Texas. Once again, the wells were free of the hole problems experienced in preceeding offset wells. COMPATIBILITY OF T K P P SOLUTIONS: Solutions of T K P P were mixed with aqueous fluids commonly encountered in drilling or completion of wells. Unlike saturated zinc bromide, concentrated T K P P solutions can be mixed in any proportion with fresh water with the only result being a decrease in solution density. Similar results were obtained with conventional oil field brines containing as much as 400 parts per million polyvalent cations, mostly calcium. Saturated solutions of calcium hydroxide also can be added to T K P P in any proportion without promoting precipitation as can concentrated hydrochloric acid solutions, conventionally used for well stimulation. The acid tends to generate a slight haze as the p H is reduced from 11.5 to approximately 8; however, this haze rapidly disappears as the p H is lowered by further addition of acid. The only fluid, common to oil field operations, that has a significant interaction with T K P P solutions was concentrated calcium chloride. Solutions of calcium chloride, spent acid, are generated during the acidization of a limestone or a dolomite formation. When solutions containing 10% calcium chloride were mixed in equal proportions with 14.5 ppg T K P P solutions, massive precipitation occurred. Similar precipitation was observed with oil field brines having calcium concentrations above 400 ppm. In normal operations, there is little chance for spent acid to contact the completion fluid as the well will usually be produced after perforation, effecting the removal of completion fluid prior to acidization. The fact that a calcium precipitation reaction can occur should be recognized by those using T K P P solutions as a clear completion fluid in well operations. A KC1 spacer is recommended to avoid completion problems in formations having high calcium brines. Not only should well fluids be compatible with reservoir fluids and minerals, but they must also be stable at surface conditions. One disadvantage of conventional halide fluids is their tendency to crystallize at ambient temperatures. Solutions containing varing amounts of T K P P were exposed to constant temperatures as low as -76°F (-60°C) for a period of 30 hours. No crystallization was observed at any temperature above 36°F (2°C) even at concentrations as high as 60% by weight. A t low fluid densities, less than 11.7 ppg, there is no evidence of T K P P crystallization even at temperatures as low as 30°F(-1°C), the freezing point of most fresh water drilling fluids. The addition of T K P P lowers the freezing point of the fluid significantly. This offers the opportunity of using a subfreezing T K P P mud to drill through strata, i.e., the permafrost in Alaska and Canada, without thawing of the
632
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formation. Problems in stability of the drilled hole as well as the rig foundation could thus be minimized. WELL LOGGING: Another advantage, unique to using T K P P in drilling fluids, would be its contribution to more accurate log interpretation. The popular neutron lifetime logs respond to the presence of chloride ions in the formation pore space. The addition of T K P P does not add any chloride ions, and the drilling fluid reacts to neutron logs much like conventional fresh water muds. The contrast in log response between T K P P and chloride fluids is also useful in the potential log-inject log procedure for determining porosity and oil saturations. As experience is gained in logging wells drilled with T K P P drilling fluids, additional benefits may become apparent. CORROSION: One property of drilling fluids that has received only minimal attention in the past is corrosiveness imparted by various additives. Additives improve the requisite properties of well fluid substantially; and, hence, increase in corrosiveness is usually ignored. This is particularly true with respect to drilling fluids containing potassium chloride to inhibit shale hydration. In 1974 Bodine, et al., recognized the potential of the phosphate ion to combat the increased corrosion rate produced by potassium chloride^ !. Accelerated corrosion is especially severe at the elevated temperatures now being encountered in deep wells and geothermal reservoirs. In most systems, phosphate corrosion inhibition is enhanced in solutions containing oxygen^ !. A l l drilling fluids are constantly aerated; and, hence, it should be no surprise to find TKPP-based fluids with reduced corrosion rates one or more orders of magnitude lower than fluids containing the same amount of potassium ion introduced by the addition of potassium chloride. Radenti et al. reported the corrosion rate of a typical potassium chloride fluid of 247 mils/year at 212°F. In contrast, they found by substituting potassium carbonate for potassium chloride, the corrosion rate was reduced to 3 mils/year^ ]. Unfortunately, potassium carbonate is not optimum as a drilling fluid additive because it can produce massive amounts of calcium precipitation, may elevate the p H to undesirable levels, and in all cases reduces the calcium ion concentration to such a low level as to promote destabililzing cation exchange with clay minerals. Corrosion rates for T K P P solutions measured at 194°F were low, 2 mils/year. Data at 400°F are equally impressive, 14 mils/year for 1020 steel 11
12
10
35. PATTONANDCORLEY
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coupons exposed to 14.5 ppg T K P P solutions for 60 days. Of special significance is the fact that T K P P reacts with steel to form a protective coating of potassium iron pyrophosphate. This coating protects the steel surface, and corrosion rates after 60 days were less than 2 mils/year even at 400° F . Although the importance of considering corrosion in the formulation of a drilling fluid is of secondary importance for shallow wells, the effect is still unmistakable. As drilling continues to deeper, hotter horizons, the more expensive rigs and tubular goods, such as those utilized in offshore operations, magnify the importance of considering corrosion in formulating an optimum drilling mud. Paralleling the corrosion problem is one involving compatibility of any well fluid with nonmetallic materials used in well completion apparatus. A l l injection wells and many producing wells are equipped with packers to isolate the casing annulus from the high temperature, pressure, and salinity characteristic of the petroleum reservoir environment. Conventional packers, as well as other well tools, utilize elastomeric materials to mechanically seal appropriate locations. At the request of an international petroleum company, a major manufacturer and supplier of down-hole equipment performed tests of the various elastomers commonly used in the construction of packers and other oil field tools. Seven of the nine most commonly used thermoplastic materials were found to be completely inert to T K P P solutions. The test included continual immersion in saturated T K P P for 21 days at 280°F. Only two elastomers, V i ton and Fluorel, showed any adverse reaction. O-rings made from these two elastomers showed minor cracking at the termination of the test. A listing of the elastomers that tested inert to T K P P solutions include nitrile, saturated nitrile ( H N B R ) , Aflas, Kalrez, P E E K , Glass-filled Teflon, and Ryton. Several of these elastomers are attacked or degraded by conventional clear completion fluids containing calcium and zinc halides. The inertness of commonly employed elastomers to T K P P is an important advantage for T K P P fluids in normal operations.
E N V I R O N M E N T A L CONSIDERATIONS: Governmental regulations relative to acceptable environmental practices have multiplied many fold in recent years. The impetus for these new regulations comes from an increased awareness and public concern for the value of maintaining the existing quality of our environment. There are many additives for well fluids, now being phased out, which were adopted without adequate regard for the effect accidental spills and disposal operations might have on fish and other forms of wildlife.
OIL-FIELD CHEMISTRY
A n example of some of the newer regulations is the restriction against the use of the popular mud dispersant, chrome lignosulfonate. It is expected that this regulation is merely the initial step toward ruling out the use of all heavy metal salts commonly employed in the formulation of well fluids because of their toxicity to aquatic life and humans. This means that the use of zinc and lead, in addition to chromium, may not be allowed in the future. A t least one major oil company has already taken steps in this direction by ruling out the use of heavy metal salts in any well fluid in their worldwide operations. Although at high concentration, T K P P is toxic to fish and shrimp. When diluted, 500-1000 P P M , it is non-toxic and expected to be both environmentally acceptable and of low risk to humans. The widespread use of T K P P in detergent formulations supports this expectation. It is listed by the U . S. Department of Transportation as a nontoxic substance relative to shipping regulations. CONCLUSIONS: Solutions of T K P P have been shown to have unique and advantageous properties for use in formulating a wide variety of well fluids. Its reasonable cost, worldwide availability, and nontoxic properties make it a preferred additive for use in many petroleum applications. It has been shown to be a most effective salt with respect to inhibiting hydration and swelling of clay minerals commonly encountered in drilling operations and/or reservoirs. Avoiding clay problems is the major impetus for the incorporation of potassium ions in well fluids, and the use of T K P P provides advantages over and above those available from other potassium salts. The use of T K P P solutions as drilling fluids for clay inhibition and increased density appears to be the prime application, at least initially. Excellent rheology and fluid loss is obtained by viscosifing with xanthan. Higher density, above 15 ppg, can be achieved by incorporating finely ground weighting agents, such as barite or hematite, in the drilling fluid. As a source of potassium ions, the addition of T K P P to a conventional drilling fluid for clay control has been shown to produce less of an adverse effect on rheology than the addition of a comparable amount of potassium chloride. Perforating fluids are conventionally prepared with soluble salts for weighting and usually filtered to avoid formation damage. Many operators perforate with the hydrostatic pressure slightly below the expected formation pressure (under balanced) to eliminate fluid loss and subsequent formation damage after the well is perforated. The nondamaging character of T K P P perforating fluids reduces the need for under balance and provides a higher degree of safety in perforation operations.
35.
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Source of Potassium for Drilling
Gravel pack completions involve placing an annular layer of gravel between the liner and the producing formation. The gravel is carried into the annular space, suspended i n a clear fluid, usually viscosified with hydroxyethylcellulose ( H E C ) . Much of the carrying fluid is lost, often purposely, to the formation and, hence, should be formulated to be nondamaging. Solutions of T K P P viscosified with xanthan are outstanding i n this respect. H E C cannot be used with high concentrations of T K P P . Packer fluids are used to provide hydrostatic balance to partially offset the reservoir pressure and eliminate a large pressure differential across the packer element. T K P P solutions more than meet the requirements of being noncorrosive, nondestructive to elastomers, variable i n density, and stable for many years. It is desirable to perforate with a well bore filled with packer fluid so that the packer can be set and the well produced as soon as the perforation operation is complete. Since T K P P solutions make superior perforation fluids, their dual use as a packer fluid is further enhanced. Work-over fluids are used routinely to kill wells for remedial operations, wash-out fill, or provide a safe environment for special logging or other well diagnostic procedures. In such operations it is often necessary to store the work-over fluid i n tanks at the well site. T K P P solutions are stable even at sub-freezing temperatures, which provides a distinct advantage over solutions of halide salts that sometimes crystallize at ambient conditions encountered in rig operation. The avoidance of a crystallization problem coupled with the noncorrosive nature of T K P P work-over fluids makes them attractive with respect to other clear work-over fluids now popular i n the industry. LITERATURE CITED: 1. 2.
Jones, F.O., Jr. J . Pet.Tech. April 1964, 441-446. Mungan, N. "Permeability Reduction through Changes i n p H and Salinity," J. Pet. Tech. Dec. 1965, 1449-1453. 3. Glenn, E.E.; Slusser, M . L . J . Pet. Tech. May 1957, 132-39. 4. Tuttle, R . N . ; Barkman, J . H . J . Pet. Tech. Nov. 1974, 1221-1226. 5. Chatterji, J . ; Borchardt, J . K . J . Pet. Tech. Nov. 1981, 2042-2056. 6. Krueger, R . F . J . Pet. Tech., Feb. 1986, 131-152. 7. Jones, L . W . U . S. Patent 3 481 869, 1969. 8. Sikorski, C . F . U . S. Patent 4 521 316, 1985. 9. Steiger, Ronald P. J . Pet. Tech. Aug. 1982, 1661-1670. 10. Radenti, G . , Palumbo, S.; Zucca, G . Pet. Eng. Intr. Sept. 1987, 32-40. 11. Boding, O. K.; Sauber, C . A. U . S. Patent 4 000 076, 1976. 12. Uhlig, H . H . I & E Chem., 44, 1952. R E C E I V E D January 27, 1989
