The precipitation reaction between aminotri(methylenephosphonic acid) (ATMP), a phosphonate used for scale prevention in high-water-volume industrial processes such as petroleum production, and calcium was systematically studied. By varying the precipitating conditions, three distinct precipitates formed:  a crystalline, sheetlike, 1:1 calcium−ATMP precipitate; an amorphous, spherical-shaped, 2:1 calcium−ATMP precipitate; and an amorphous, spherical-shaped, 3:1 calcium−ATMP precipitate. Corresponding batch dissolution experiments showed that as the precipitate calcium−ATMP molar ratio increased from 1:1 to 2:1 to 3:1, the rate of dissolution and the equilibrium solubility limit decreased significantly. The significance of these observations was evident when the release characteristics of each precipitate from porous media were studied as related to ATMP use in oil-recovery systems. The 3:1 calcium−ATMP precipitate was released from porous media in a much slower manner than the other two precipitates, strongly suggesting that the 3:1 precipitate is most suitable for use in oil recovery.

Phosphonates are water treatment chemicals that are effectively utilized in many industrial processes as dispersants, bleaching agents, or scale and corrosion inhibitors. In many of these applications, the phosphonates are able to react with divalent cations such as calcium to form stable divalent cationphosphonate precipitates. The focus of this paper is to define the conditions under which distinct calciumphosphonate precipitates will form and to study how each of these precipitate's unique chemical and physical properties govern the release of phosphonate from porous media. The phosphonate used in this study was (1-hydroxyethylidene)-1,1-diphosphonic acid (HEDP). By variation of the pH and calcium/ HEDP molar ratio in solution, two distinct precipitates were formed: (1) a soluble, fibrous 1:1 calcium/ HEDP precipitate; and (2) a less soluble, spherical 2:1 calcium/HEDP precipitate. Critical pH values that define the conditions under which each distinct precipitate forms were identified. Below the first critical pH value, the 1:1 precipitate formed, while above the second critical pH value, the 2:1 precipitate formed. Finally, coreflood and micromodel experiments showed that the release of 2:1 precipitate from porous media was significantly slower than that of 1:1 precipitate, suggesting that the 2:1 precipitate is better suited for phosphonate treatments in oil field applications. The release of a precipitate mixture (one which contains both distinct precipitates and has a calcium/HEDP molar ratio of 1.4:1) from a micromodel reconfirmed this phenomenon.

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The problem of scaling in petroleum production systems has been well documented over the past fifty years. The most widely used method today to treat this scaling problem is the injection of threshold scale inhibitors into a formation where they are retained during a shut-in period and subsequently released when production is resumed. The success of a "squeeze treatment" is often judged by its effective lifetime in inhibiting scale in a reservoir system, and this lifetime is dictated by the retention/release mechanisms of inhibitor in the reservoir. The focus of this paper is to study the precipitation/dissolution of CaHEDP in a porous medium and to elucidate the important factors that affect the release of this precipitate. Experiments carried out in ceramic cores indicated that precipitation squeezes offer longer squeeze lifetimes and more HEDP retention than adsorption squeezes. Micromodel experiments showed that the CaHEDP precipitate placed in porous media was made up of long, fibrous particles preferentially situated in pore throats. The elution from the micromodel indicated that slow dissolution of apparently strong pore throat plugs was dictating the long tailing region. Finally, multiple shut-in experiments performed in ceramic cores showed that while the amount of CaHEDP retention per shut-in did not increase with successive shut-ins, an enhanced returns effect was observed with respect to the squeeze lifetime. Introduction The problem of scale deposition in oil and gas production systems has been well documented in past yews. Scale is usually defined as any undesirable precipitation caused by either the mixing of two incompatible brines or the sudden changes in produced fluid conditions (i.e. temperature, pressure, pH).Scale nucleation and growth can occur anywhere in a production system, most notably on surface production equipment, on the wellbore surface, or in the near wellbore formation. Continuous scale buildup in untreated wells can limit the production efficiency of a reservoir to the point where production has to be discontinued and the system has to be cleaned to eliminate the scale. Hence, it becomes economically feasible to address this scaling problem in production systems. The most widely used method today to combat the problem of scale is to inject (i.e. squeeze) threshold scale inhibitors into the formation to prevent or slow the crystal nucleation and growth of scale. The advantages of treating oil wells by the squeeze technique have been known for over fifty years. In atypical squeeze treatment, a slug of scale inhibitor, along with a brine overflush, is injected into a reservoir where it is shut-in for twenty-four hours. During the shut-in period, the inhibitor is retained in the formation by one of three mechanisms:the inhibitor is adsorbed onto the surface of the formation;the inhibitor precipitates with available cations in the reservoir system; orthe inhibitor solution links into small fractures in the formations After the shut-in period, production is resumed and the inhibitor is released back into the produced fluid where it is able to prevent scale from forming. The success of a squeeze treatment is often judged by the length of time in which inhibitor is released back into the produced fluid at concentrations effective in preventing scale. This release of inhibitor, along with the squeeze lifetime, is governed by the inhibitor retention mechanism taking place during the shut-in period. Therefore, it becomes important to have a fundamental understanding of the retention/release mechanisms of inhibitor from a porous medium.

Meridianiite, MgSO 4 Á11H 2 O, is the most highly hydrated phase in the binary MgSO 4 -H 2 O system. Lower hydrates in the MgSO 4 -H 2 O system have end-member analogues containing alternative divalent metal cations (Ni 2? , Zn 2? , Mn 2? , Cu 2? , Fe 2? , and Co 2? ) and exhibit extensive solid solution with MgSO 4 and with one another, but no other undecahydrate is known. We have prepared aqueous MgSO 4 solutions doped with these other cations in proportions up to and including the pure end-members. These liquids have been solidified into fine-grained polycrystalline blocks of metal sulfate hydrate ? ice by rapid quenching in liquid nitrogen. The solid products have been characterised by X-ray powder diffraction, and the onset of partial melting has been quantified using a thermal probe. We have established that of the seven end-member metal sulfates studied, only MgSO 4 forms an undecahydrate; ZnSO 4 forms an orthorhombic heptahydrate (synthetic goslarite), MnSO 4 , FeSO 4 , and CoSO 4 form monoclinic heptahydrates (syn. mallardite, melanterite, bieberite, respectively), and CuSO 4 crystallises as the well-known triclinic pentahydrate (syn. chalcanthite). NiSO 4 forms a new hydrate which has been indexed with a triclinic unit cell of dimensions a = 6.1275(1) Å , b = 6.8628(1) Å , c = 12.6318(2) Å , a = 92.904(2)°, b = 97.678(2)°, and c = 96.618(2)°. The unit-cell volume of this crystal, V = 521.74(1) Å 3 , is consistent with it being an octahydrate, NiSO 4 Á8H 2 O. Further analysis of doped specimens has shown that synthetic meridianiite is able to accommodate significant quantities of foreign cations in its structure; of the order 50 mol. % Co 2? or Mn 2? , 20-30 mol. % Ni 2? or Zn 2? , but less than 10 mol. % of Cu 2? or Fe 2? . In three of the systems we examined, an 'intermediate' phase occurred that differed in hydration state both from the Mg-bearing meridianiite end-member and the pure dopant end-member hydrate. In the case of CuSO 4 , we observed a melanterite-structured heptahydrate at Cu/ (Cu ? Mg) = 0.5, which we identify as synthetic alpersite [(Mg 0.5 Cu 0.5 )SO 4 Á7H 2 O)]. In the NiSO 4 -and ZnSO 4 -doped systems we characterised an entirely new hydrate which could also be identified to a lesser degree in the CuSO 4 -and the FeSO 4 -doped systems. The Ni-doped substance has been indexed with a monoclinic unit-cell of dimensions a = 6.7488(2) Å , b = 11.9613(4) Å , c = 14.6321(5) Å , and b = 95.047(3)°, systematic absences being indicative of space-group P2 1 /c with Z = 4. The unit-cell volume, V = 1,176.59(5) Å 3 , is consistent with it being an enneahydrate [i.e. (Mg 0.5 Ni 0.5 )SO 4 Á9H 2 O)]. Similarly, the new Zn-bearing enneahydrate has refined unit cell dimensions of a = 6.7555(3) Å , b = 11.9834(5) Å , c = 14.6666(8) Å , b = 95.020(4)°, V = 1,182.77(7) Å 3 , and the new Febearing enneahydrate has refined unit cell dimensions of a = 6.7726(3) Å , b = 12.0077(3) Å , c = 14.6920(5) Å , b = 95.037(3)°, and V = 1,190.20(6) Å 3 . The observation that synthetic meridianiite can form in the pres...