Synthesis, characterization, and working mechanism of a synthetic high temperature (200°C) fluid loss polymer for oil well cementing containing allyloxy-2-hydroxy propane sulfonic (AHPS) acid monomer

Evaluation and Optimization of Cement Slurry Systems for Ultra-Deep Well Cementing at 220 °C

With the depletion of shallow oil and gas resources, wells are being drilled to deeper and deeper depths to find new hydrocarbon reserves. This study presents the selection and optimization process of the cement slurries to be used for the deepest well ever drilled in China, with a planned vertical depth of 11,100 m. The bottomhole circulating and static temperatures of the well were estimated to be 210 °C and 220 °C, respectively, while the bottomhole pressure was estimated to be 130 MPa. Laboratory tests simulating the bottomhole conditions were conducted to evaluate and compare the slurry formulations supplied by four different service providers. Test results indicated that the inappropriate use of a stirred fluid loss testing apparatus could lead to overdesign of the fluid loss properties of the cement slurry, which could, in turn, lead to abnormal gelation of the cement slurry during thickening time tests. The initial formulation given by different service providers could meet most of the design requirements, except for the long-term strength stability. The combined addition of crystalline silica and a reactive aluminum-bearing compound to oil well cement is critical for preventing microstructure coarsening and strength retrogression at 220 °C. Two of the finally optimized cement slurry formulations had thickening times more than 4 h, API fluid loss values less than 50 mL, sedimentation stability better than 0.02 g/cm3, and compressive strengths higher than 30 MPa during the curing period from 1 d to 30 d.

Evaluation of the Na-EDTMP/borax system as a non-dispersing, high temperature retarder for oil well cement

For well cementing at temperatures above 120 °C, thermal thinning depicts a major problem, promoting particle sedimentation via decreasing slurry viscosities. This is partly caused by dispersing properties of common high temperature retarder systems and can lead to imperfect zonal isolation, endangering the stability of the wellbore. Counteracting additives tend to start losing their effectiveness at temperatures >140 °C. Other options are often not economically sufficient, increase system complexity or show negative interactions with other additives. Hence, this work presents a comprehensive study on the sodium ethylenediamine tetra(methylene phosphonate) (Na-EDTMP)/borax retarder system, which was found to combine sufficient retardation with low thermal thinning, leading to an enhanced slurry stability at high temperatures. Thickening times (TT's) from 7 to 13 h (increasing with temperature) were achieved from atmospheric pressure and 50 °C up to high pressures and temperatures (HP/HT) of 19.0 kpsi and 200 °C bottom hole circulating temperature (BHCT). Furthermore, On/off-cycle HP/HT consistometer tests at 160 and 190 °C and rheological measurements were performed to examine stability of the slurry's viscosity. Experiments with fluid-loss additives show potential compatibility with other additives. Total retarder dosages of 0.97-2.64 % bwoc (by weight of cement) were applied. Compared to prior literature, higher Na-EDTMP/borax ratios (0.29-0.34 vs. 0.055) were found to improve retarding performance probably by enhancing synergetic effects. The slurries featured a sufficient initial viscosity (<40 Bc) and a constant pumpability (10-25 Bc) during the tests followed by a swift setting and compressive strength (CS) development. Additionally, high slurry stability was shown and compatibility with common fluid-loss additives is probable. Main disadvantage was the relatively high sensitivity of the system, especially at moderate temperatures, requiring exact dosage. Summarizing, the Na-EDTMP/borax retarder system might present a low-complexity opportunity for common high temperature retarders, avoiding thermal thinning while improving slurry stability.

The Coordination of Aluminum Sulfate with a Water-Soluble Block Copolymer Containing Carboxyl, Amide, Sulfonic and Anhydride Groups Providing Both Accelerating and Hardening Effects in Cement Setting

Two water-soluble block copolymers composed of acrylic acid (AA), 2-acrylamido-2-methylpropane sulfonic acid (AMPS), and optionally maleic anhydride (MAH) were synthesized through ammonium persulfate-catalyzed free radical polymerization in water. The introduction of aluminum sulfate (AS) into the resulting mixtures significantly reduced the setting times of the paste and enhanced the mechanical strength of the mortar compared to both the additive-free control and experiments facilitated solely by pure AS. This improvement was primarily attributed to the inhibition of rapid Al3+ hydrolysis, which was achieved through coordination of the synthesized block copolymers, along with the formation of newly identified hydrolytic intermediates. Notably, the ternary copolymer (AA-AMPS-MAH) exhibited superior performance compared to that of the binary copolymer (AA-AMPS). In the early stages of cement setting, clusters of ettringite (AFt) were found to be immobilized over newly detected linkage phases, including unusual calcium silicate hydrate and epistilbite. In contrast to the well-documented role of polymers in retarding cement hydration, this study presents a novel approach by providing both accelerating and hardening agents for cement setting, which has significant implications for the future design of cement additives.

Effect of a 2-Acrylamido-2-methylpropanesulfonic Acid-Based Fluid Loss Additive on the Hydration of Oil Well Cement

The fluid loss additive is to prevent the cement slurry from filtrating water to the formation under pressure. 2-Acrylamido-2-methylpropanesulfonic acid (AMPS)-based fluid loss additive mainly works by adsorbing on the surface of cement particles. The adsorption affects cement hydration. In this paper, the effect of one kind of AMPS-based fluid loss additive (A-FLA) on the hydration of oil well cement was studied. The water loss, setting time, thickening time, and compressive strength of cement slurry with various amounts of FLA were measured. In addition, the hydration heat of the cement slurry, FLA adsorption isotherm on cement particles, and hydration minerals were studied. The results showed that A-FLA had a good water loss control ability. The water loss of the cement slurry decreased slowly with the increase of A-FLA dosage when the adsorption capacity exceeded 4.47 mg/g. The low adsorption capacity of A-FLA (less than 4.47 mg/g) had a significant impact on the thickening time. With an adsorption capacity greater than 4.47 mg/g, the thickening time varied minimally. A-FLA mainly delayed the hydration of C3S at 1 day and reduced the production amorphous phase.

Synthesis and Evaluation of Highly Inhibitory Oil Well Cement Retarders with Branched-Chain Structures

Cementing at medium temperature and high temperature (90-150 °C) is facing challenges on account of the properties of the retarders. Except for the thermal stability, abnormal gelation, such as "bulging" and "stepping", often takes place and results in safety problems. In this article, the synthesis of a new retarder DRH-150 was introduced. First, a main chain with thermal-resistant groups, 2-acrylamido-2-methylpropanesulfonic acid-acrylic acid (AMPS-IA-AA) was prepared by free radical polymerization. Second, the retarder with a branched structure was synthesized by the grafting reaction. Evaluation of the construction performance showed that, within the temperature range from 90 to 150 °C, the initial viscosity of the cement slurry with DRH-150 was less than 15 Bc, exhibiting an adjustable thickening time and a dosage sensitivity of less than 20%. Meanwhile, no abnormal gelation phenomenon was observed. Referring to the static gelation, both the transition time and the starting strength time (1 MPa) were short. The overall results proved that the retarder DRH-150 might ensure the safety of well cementing and improve the wellbore sealing effect in deep wells, ultradeep wells, and complex wells.

Study of a High-Temperature and High-Density Water-Based Drilling Fluid System Based on Non-sulfonated Plant Polymers

The environment-friendly water-based drilling fluid system developed for the petroleum development industry cannot successfully withstand temperatures up to 180 °C, and most high temperature-resistant additives with sulfonic acid groups that have been successfully applied to water-based drilling fluid are not good for environmental protection. In order to solve the above technical problems, a non-sulfonated filtrate reducer and viscosity reducer with resistance to high temperature were prepared by using humic acid, lignin and a multifunctional monomer as raw materials. In laboratory experiments, the molecular weights of the FLO-H filtrate reducer and the VR-H viscosity reducer were 5.45 × 10⁵ g/mol and 8.51 × 10³ g/mol, respectively, and all of them showed good high-temperature resistance. The API filtration loss of the bentonite-base slurry with 3.0 wt% FLO-H was only 6.2 mL, which indicated that FLO-H had a prominent reduction in filtration loss after aging at high temperature. When the dosage of VR-H was 1.0 wt%, the plastic viscosity of the water-based drilling fluid after aging at 200 °C decreased from 71 mPa·s to 55 mPa·s, which provided excellent dispersion and dilution. The high-temperature and high-density water-based drilling fluid containing the FLO-H filtrate reducer and the VR-H viscosity reducer had good suspension stability and low filtration performance at the high temperature of 200 °C, which can meet the requirements of high-temperature deep well drilling.

Recent Advances in Deep Eutectic Solvents as Shale Swelling Inhibitors: A Comprehensive Review

Inhibitors have evolved from their primary function of controlling swelling during hydraulic fracturing processes in shale reservoirs. This study provides a comprehensive review of recent deep eutectic solvent (DES) advancements as inhibitors in swelling inhibition techniques. The swelling inhibitory potentials and mechanisms of DESs have been studied analytically and compared to existing conventional inhibitors. The functional effects of concentration, temperature, and types of DES are explored. Data on the effect of DES on rheology, swelling, zeta potential, shale cutting recovery, surface tension, particle size distribution, XRD, and FTIR analyses are presented. Along with preparation procedures, environmental concerns and applications of DESs in several fields are discussed. This study suggests that DESs are preferable swelling inhibitors due to their inhibitory performance, cost-effectiveness, and environmental friendliness. Moreover, this review includes guidelines and recommendations for selecting and designing DES to inhibit swelling more effectively.

Fabrication of a state of the art mesh lock polymer for water based solid free drilling fluid

Polymers are used widely in various kinds of drilling fluid to maintain the proper rheological properties. However, most of them are not available for high-temperature or salt solutions due to poor temperature and salt resistance. To ameliorate the temperature and salt resistance of polymer used in the solid-free water-based drilling fluid, a novel polymer with a kind of "Mesh-Lock" reinforced network cross structure, named PLY-F [main monomer acrylic acid (AA), acrylamide (AM), functional monomers 2-acrylamide-2-methylpropanesulfonic acid (AMPS) N-vinylpyrrolidone (NVP) and C₁₆DMAAC] were prepared through free radical polymerization of an aqueous solution of organic cross-linking agent pentaerythritol triallyl ether (PTE) as a cross-linking system, Potassium persulfate (KPS) and sodium bisulfite as the initiator for the first time. The surface morphology, crosslinking architecture and temperature and salt resistance of the PLY-F were fully characterized with several means including SEM, FT-IR, ¹³CNMR, dynamic rheology, and long-term thermal stability. The SEM observation indicated that the PLY-F exhibits a regular "Mesh-Lock" reinforced network cross structure. FT-IR, ¹³CNMR analysis indicated that the characteristic functional groups of each monomer such as AM, AA, AMPS and NVP were all together in the polymer. The results show that the apparent viscosity retention rate of the PLY-F in the potassium formate solution (with a density of 1.3 g/cm³) was more than 80% after heat rolling for 72 h at 200 °C and the plastic viscosity retention rate reached 90.3%. Moreover, the salt resistance of the polymer can reach the density of 1.4 g/cm³ (potassium formate solution) under 200 °C and the temperature resistance can reach 220 °C under the density of 1.3 g/cm³ (potassium formate solution). Besides, the PLY-F still has good rheological properties in other saturated solutions (NaCl, HCOONa) under 210 °C.

Synthesis and characterization of comb-shaped copolymer as a filtration reducer and comparison with counterparts

A comb-shaped copolymer of 2-acrylamide-2-methyl propane sulfonic acid (AMPS), allyl polyoxyethylene ether (APEG), N-vinyl-2-pyrrolidone (NVP) and sodium styrene sulfonate (SSS) was synthesized by free-radical polymerization. The structure of the comb-shaped copolymer was characterized by Fourier transform infrared (FTIR) spectroscopy, and its molecular weight was determined by gel permeation chromatography (GPC). FTIR measurements and environmental scanning electron microscopy (ESEM) analysis were used to characterize the working mechanism of different filtrate loss reducers. Thermogravimetry and differential scanning calorimetry (TG-DSC) results showed that thermal degradation of the copolymer was significant only after 295.24 °C. The comb-shaped copolymer helped reduce filtration, while maintaining the rheological properties of the drilling fluid at high temperature and high salinity conditions as long PEG chains sterically stabilized colloids by protruding into the suspension. The filtration control of the comb-shaped copolymer was comparable to that of the sulfonated phenolic resin (SMP) mixture and outperformed AM/AMPS/NVP/SSS (NS-1) and polymeric product PAC in terms of high-temperature resistance and rheological advantages. The morphology of the comb-shaped copolymer was found with a compact 3-D film structure due to the intramolecular and intermolecular association by hydrogen bonding in the side chains. Small curly debris at high temperature and salinity remained capable of filtration control. The NS-1 had a lower temperature resistance, as large areas of flaky films thermally degraded into a small chain structure at 180 °C. Only separated filiform and coarse lines were found in PAC with a linear structure that makes the drilling fluid more viscous. Compact and structured films were formed with the SMP mixture at high temperature and salinity.

A Novel Terpolymer as Fluid Loss Additive for Oil Well Cement

A terpolymer comprised of sodium styrene sulfonate (SSS), fumaric acid (FA), and acrylamide (AM) was synthesized by aqueous free radical copolymerization and evaluated as fluid loss additive for oil well cement. The chemical structure and performance of the terpolymer were characterized by Fourier transform infrared (FTIR) spectroscopy and thermal gravimetric analysis (TGA); the molecular weight and its distribution were determined by gel permeation chromatography (GPC). The optimum reaction conditions of polymerization were obtained: a reaction temperature of 50°C, a mass ratio of SSS/FA/AM 4 : 2 : 14, initiator 0.1%, and reaction time of 4 h; characterization indicated that the SSS/FA/AM had a certain molecular weight and excellent temperature-resistant and salt-resistant properties. The results show that SSS/FA/AM has a good fluid loss performance, in which the API fluid loss of the oil cement slurry could be controlled within 100 mL at 160°C. In addition, it had little effect on the cement compressive strength. The results of scanning electron microscopy (SEM) of the filter cake showed that SSS/FA/AM could be adsorbed on the surface of the cement particles and produce a hydrated layer to prevent fluid loss from the oil well cement.

Copolymer SJ-1 as a Fluid Loss Additive for Drilling Fluid with High Content of Salt and Calcium

A ternary copolymer of 2-acrylamide-2-methyl propane sulfonic acid (AMPS), acrylamide (AM), and allyl alcohol polyoxyethylene ether (APEG) with a side chain polyoxyethylene ether(C2H4O)nSJ-1 were designed and synthesized in this work. Good temperature resistance and salt tolerance of “–SO3-” of AMPS, strong absorption ability of “amino-group” of AM, and good hydrability of side chain polyoxyethylene ether(C2H4O)nof APEG provide SJ-1 excellent properties as a fluid loss additive. The chemical structure of ternary copolymer was characterized by Fourier transform infrared (FTIR) spectroscopy. The molecular weight and its distribution were determined by gel permeation chromatography (GPC). The API fluid loss of drilling fluid decreased gradually with the increasing concentration of NaCl and CaCl2in the mud system. SJ-1 was applied well in the drilling fluid even at a high temperature of 220°C. Results of zeta potential of modified drilling fluid showed the dispersion stability of drilling fluid system. Scanning electron microscopy (SEM) analysis showed the microstructure of the surface of the filter cake obtained from the drilling fluid modified by SJ-1.