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In certain regions of oil and gas operations, lost circulation is a common occurrence, especially when a majority of the openhole exposed during primary cementing is carbonate-based formations. This can lead to lost circulation risks in most applications. To overcome lost circulation risks during primary cementing, a new tailored spacer system shows to improve the cement placement success. The manuscript discusses the quality assurance and performance testing with field cases demonstrating the value contributions of the spacer for achieving zonal isolation requirements as well as the top of cement objectives. The work efforts presented shows a spacer meeting and sometimes showing incremental wellbore strengthening in comparison to the published literature for existing available spacers used to overcome similar lost circulation risks.

Lost circulation (LC), commonly encountered in drilling and cementing operations, can be a costly problem that increases non-productive time, especially in highly permeable formations. When LC occurs during cementing, zonal isolation can be compromised. Risks associated with LC affect most applications, including offshore operations. This paper presents the evaluation of a new tailored spacer system (TSS) designed to effectively mitigate LC and its use in deepwater cementing operations to meet zonal isolation objectives.

Mg doped ZnO nanoparticles decorated on graphene oxide (GO) sheets were synthesized by a wet impregnation method. The effect of Mg doping on ZnO and ZnO-GO composite has been evaluated by using x-ray diffraction (XRD), Williamson-Hall Plot (W H Plot), field emission scanning electron microscope (FESEM), transmission electron microscopy (TEM) and energy dispersive x-ray spectroscopy (EDX). The physical parameters of as-prepared samples were estimated by XRD data. FESEM and HR-TEM images showed the uniform distribution of nanoparticles on GO crumpled paper like sheet. Solar light photocatalytic activities of samples were evaluated spectrophotometrically by the degradation of p-nitrophenol (PNP) and indigo carmine (IC) solution. Mg ZnO decorated on GO sheets exhibit excellent catalytic efficiency compared to all other prepared samples under identical conditions, degrading PNP and IC nearly 99% within 60 min under sunlight. The effective degradation by Mg ZnO decorated on GO sheet would be due to extended solar light absorption, enhanced adsorptivity on the composite catalyst surface and efficient charge separation of photo-induced electrons. Finally, plausible mechanism was suggested with the help of scavengers study.

Bi 2 O 3 -bentonite nanocomposites successfully synthesized by intercalation method, are used for photocatalytic degradation of Rhodamine B (Rh B) under visible light irradiation. Bi 2 O 3 -bentonite shows enhanced photocatalytic efficiency than pure Bi 2 O 3 due to intercalation with bentonite. Removal of Rh B is achieved upto 98.5% using 3 gL −1 photocatalyst at pH 3. It is found that increase in light absorption and decrease in electron-hole recombination enhances photocatalytic efficiency. Photocatalytic degradation of Rh B by Bi 2 O 3 -bentonite proceeds via advanced oxidative process. The plausible mechanism of photocatalytic degradation Rh B reported by LC-MS shows generation of different degradation products including benzoic acid and benzonium ion.

Lost circulation is a recurring and costly challenge for the oil and gas industry. Losses range from seepage to total and financial effects, including nonproductive time and remedial operational expenses, which can increase potential risks to the operator. To address this issue, a tunable cement-based lost circulation treatment solution has been developed that is most suitable for partial to total losses, particularly when particulate-based solutions are not effective; the solution is primarily intended to cure losses while drilling. Unlike conventional lost circulation materials (LCMs) that cure losses by mechanical bridging of particles, the thixotropic cement solution's effectiveness arises from its unique chemical composition, which is ideal when flow paths are too large to be plugged by particles. The new lost circulation treatment solution is thixotropic with a density range of 10 to 15 lbm/gal working in temperatures up to 250°F. The formulation can be mixed with fresh water, seawater, or seawater with up to 14% NaCl. It is designed and tested in accordance with API RP 10B2 (2013) procedures for thickening time (TT), compressive strength, static gel strength, fluid loss, and rheology. During the TT on-off-on test, the formulation builds gel strength when shear is reduced and regains fluidity when shear is reapplied. The formulation developed rapid static gel strength and an early compressive strength up to 500 psi. The reversible gelation behavior is demonstrated through multiple shear on-off cycles. This solution is operationally convenient to apply because it can be pumped through the bottomhole assembly (BHA), thus reducing trip times. Because of its acid solubility, it can be used across production zones. The unique properties of gaining rapid gel strength reversibly and a good compressive strength render this solution effective for treating a wide range of lost circulation events during drilling. A wider density window might minimize the potential risk of inflow when treating losses.

Recent deepwater discoveries in CO2-laden presalt regions have posed new drilling and cementing challenges associated with salt and CO2. Salt can react and gel cement slurry prematurely, resulting in pumping and displacement issues. Further, creeping salts can compromise the mechanical integrity of the cement sheath. Carbonic acid under downhole conditions can react with the cement sheath and adversely affect its integrity. Design of a cementing solution for such environments requires a holistic approach that addresses the chemical and mechanical effects of well operations on the cement sheath during the life of the well. A combination of chemistry, engineering modeling, thermodynamics, chemical reaction, and experimental characterization was used in this study. The work evaluates the influence of dissolution of different levels and types of salt on the cement slurry's physical properties and modeling the cement sheath response for salt creep loads. It also involved conducting long-term high-pressure/high-temperature (HP/HT) cement carbonation experiments and developing a mathematical model to predict the long-term possibility of corrosion under downhole conditions. Slurry was designed such that the blend is suitable for salt and presalt zones. By virtue of its chemical nature, the slurry resists dissolution of salt and hence does not cause premature gelling. Mechanical characterization and further engineering analysis predicted that the cured cement had good resistance to failure caused by mechanical loads resulting from salt creep. The slurry was tested to confirm that it mitigates the effect of CO2 corrosion on cement under static and dynamic test conditions. The developed model predicted accurately the extent of corrosion expected under downhole conditions. The present work provides a solution to cementing salt and presalt zones, with a sound understanding of the associated risks and their mitigation. The cement designs and engineering models developed as part of this study can help reduce the risk of damage to the cement sheath and casing collapse across salt zones. They also help mitigate the corrosion of cement when exposed to CO2 present in presalt zones.

Long-term zonal isolation requires effective mud displacement. One best practice for achieving this is to use the highest pumping rates allowable during cementing operations. However, in zones with a narrow pressure window, fracture pressure sometimes does not support higher flow rates. This is because high flow rates result in high friction pressures, which can exceed the fracture pressure of the formation. This is an issue particularly in long horizontal wells. In such cases, fluid rheology is important for achieving better displacement efficiency without inducing fractures. The current work discusses a procedure in which the rheology of cement slurry can be tuned such that good displacement efficiency is attained at sufficiently low flow rates. The tuning should be such that the shear stress is almost invariant for varying shear rates. This reduces the friction pressures considerably during placement. A hydraulics model was run on an example well configuration with a narrow margin situation. Pressure response and displacement characteristics of two types of slurries were analyzed. These include conventional and modified slurry, the latter of which was tuned for better mud displacement at low flow rates. The modified slurry showed an increase in yield point with a shear stress profile that was almost invariant for the range of shear rates analyzed. A decrease in equivalent circulating density (ECD) occurred as a result of rheology modification, and this resulted in avoiding ECDs exceeding the fracture gradient at critical locations. Displacement efficiency increased by 10% when using the modified slurry at the same pump rates as those used for the conventional slurry. On the other hand, when targeting the same displacement efficiency as the conventional slurry, the required pump rates for the modified slurry were lower. This study indicates that better displacement can be attained through rheology modification, even by using relatively low flow rates, thereby maintaining low ECDs to help ensure effective cementing operations.

The primary challenge with weak production zones is severe to total circulation loss resulting from natural fractures or low fracture pressures. A highly thixotropic engineered cement system has been used successfully in the field in several severe-to-total-loss treatment procedures involving weak nonproducing zones. This paper presents an investigation of this cement system's response to acid treatment and the possibilities of extending its use as a temporary plug to cure losses in weak production zones while helping minimize formation damage. Tests were performed to understand the response of the highly thixotropic engineered cement system to acid treatment. These tests included acid immersion of cured cement cubes and exposure of set cement to a continuous supply of acid by exerting a differential pressure in an acid core flow apparatus. A reacted cement core forms a conductive path, resulting in a subsequent decrease in differential pressure or an increase in flow rate. Dependency on temperature and differential pressure were studied. Experimental observations indicated that there was a formation of conductive path caused by a cement reaction when subjected to acid treatment. However, complete dissolution is a prolonged process and is unlikely to occur within the typical acid treatment times used in the field. If sufficient differential pressure is provided to allow the acid to diffuse through the entire volume of cement, a regain in permeability can be easily achieved, even with short exposure times. It has been observed that the time required to form a wormhole decreases as differential pressure increases. When acid was replaced with water, no wormhole formation or increases in the permeability of set cement occurred. This confirms that the wormhole formation is a result of the chemical reaction of cement with acid. The study presented in this paper confirms that the engineered cement system is amenable for acid treatment. This provides opportunities to use this cement system to treat severe and total losses, as well as provide wellbore strengthening in production zones. Such an operation helps ensure that the production zone is well prepared for a successful primary cement treatment without compromising production.

Summary Polymeric viscosifiers are added to cement slurries for a variety of reasons, including prevention of particle settling and control of fluid loss, gas migration, and free water. Many of these functions are critically important after the cement slurry has been placed behind the casing but before the setting of the cement. Some functions, such as particle-settling prevention, are also important during the pumping phase. Unfortunately, most of the viscosifying polymers suffer from thermal thinning at bottomhole temperatures, especially under shear. The amount of polymer required to maintain the required level of viscosity at elevated bottomhole temperatures causes excessive surface-slurry viscosification at ambient temperature. Pumping such slurries can require higher pump pressures, which, in some cases, might exceed formation breakdown pressures causing unintended fractures.This becomes a serious challenge when the window between the fracture pressure and the pore pressure of the formation is narrow. It would be a significant improvement to oilfield cementing technology to develop polymers that do not cause excessive slurry viscosification on the surface but gradually increase the slurry viscosity as it reaches downhole temperatures, with the maximum viscosity reached at the time the slurry becomes static behind the casing. This paper describes a chemical method, not based on encapsulation, for modifying biopolymers and their derivatives—for example, hydroxyethylcellulose (HEC) and xanthan—that renders them insoluble in cement slurries at room temperature (RT). When the cement slurries containing modified HEC are heated, the slurries develop viscosity upon heating, as reflected by changes to slurry rheology with temperature. The method also provides for increased viscosification efficiency of the modified polymers because of the increased molecular weights of the modified biopolymer products. Synthesis details, slurry rheologies at different temperatures, and job-placement simulation details are presented. A possible reaction mechanism that is operative in the chemical-modification step is also discussed.

The industry is exploring for oil and gas in reservoirs that contain in-situ corrosive fluids, such as CO2 and H2S. In addition, there has been a push to sequester the CO2 produced from various industrial sources. To this effect, geological carbon dioxide storage is an economically viable method to help reduce greenhouse emissions and CO2 injection is an effective enhanced oil recovery (EOR) method. Ensuring long-term safety and efficacy is one of the primary technical challenges in this context attributed to potential degradation of the cement sheath, creating pathways for leakage. Design of CO2-resistant slurries is an important mitigation approach. This paper discusses an experimental evaluation of the chemical effects of CO2 on key properties of cement sheaths. Twelve slurries were developed based on the two primary approaches to mitigate CO2 degradation: (a) reduction of reactive hydration products and (b) reduction of cement matrix permeability. This paper reports results for four selected slurries in a carbonic acid environment. Seven samples of each slurry were cured and then subjected to an aqueous CO2 environment (carbonic acid) for 15, 30, 90, 180 and 365 days. Downhole conditions were simulated by running the carbonation tests at 165°F and constant CO2 partial pressure of 2, 000 psi. At the specified time points, samples were removed to perform chemical tests (inductive coupled plasma [ICP], water analysis, X-ray diffraction [XRD], thermogravimetric analysis [TGA], and dye penetration) and physical tests (ultimate compressive strength [UCS], Brinell hardness, permeability, and porosity). The general observation was improvement in terms of physical properties up to 90 days, followed by a decrease that continued throughout the experiment period. Formulations mixed with NaCl brine were additionally degraded by salt leaching. The best resistance to degradation was obtained using formulations with reduced portland content and elastomers to reduce permeability. Higher compressive strength was correlated with low permeability. Most slurries had a permeability lower than 0.1 millidarcy (mD) after one year of exposure. Chemical testing supports the interpretation that the early improvement in physical properties can be attributed to carbonate precipitation, while later degradation is attributed to the formation and leaching of calcium bicarbonate. Some slurries contained sodium chloride in mix water at saturation levels. In which case, sodium chloride leached out of the cement sheath and was confirmed by water analysis. In the carbonic acid (wet) environment, a dense layer of calcium carbonate was observed that corresponded to an increase in Brinell hardness This study demonstrates the efficacy of a testing protocol that can be used to evaluate various cement blends for long-term integrity under downhole conditions and different forms of CO2 attack. The results were used to design cement systems more resistant to CO2 degradation than conventional slurries.

Downhole CO2 in the presence of water forms carbonic acid, which reacts with cement. Some of the final products are water soluble and are leached out. This could cause loss of long term mechanical integrity of the cement sheath, among other issues. Hence, long term prediction of cement sheath carbonation is important to help ensure the cement system designed for CO2 environments creates and maintains zonal isolation throughout the life of the well. This paper discusses a series of long term tests performed to better understand the effects of CO2 on cement quantitatively. CO2 downhole generally falls within two categories dry CO2, which is a result of carbon capture and sequestration (CCS) activities, and wet CO2, which accounts for naturally formed CO2. Cement samples are tested under downhole conditions of high-pressure/high-temperature (HP/HT) in two different environments supercritical CO2 and carbonic acid, which represent the two different types of CO2 present in the wellbore, respectively. Different types of cement blends have been used in the study to understand the effects of cement composition on corrosion caused by CO2. Cement samples were periodically withdrawn from the autoclaves to test for transient permeability, compressive strength, Brinell hardness, and chemical composition (X-ray diffraction [XRD], inductively coupled plasma [ICP] tests, pH indicator testing, and thermogravimetric analysis [TGA]). All of the samples were tested for a total of one year. It was observed that chemistry played a very important role in determining how resistant the cement is to attack from CO2. This study helped provide clear insight into a method that can be used for testing different cement blends for long-term integrity under varying corrosive environments. Knowing the performance of particular cement chemistry under downhole conditions provided considerable benefit in terms of understanding long term integrity of the cement sheath.

A number of reservoirs around the globe are deep, and often it is necessary to drill and cement through salt zones to reach the reservoir section. Brazil offshore is one example where reservoirs are buried deep, and the salt zones there are quite challenging to drill through and cement. Many of these salt zones contain chemically reactive salts, such as magnesium and calcium chloride, and usually pose unique challenges during placement of the slurry and subsequent cement slurry hydration and compressive strength development. These salts, especially MgCl2, chemically interact with the cement slurry, thereby altering the mechanism and kinetics of cement hydration, leading to premature gelation and shorter thickening times. Mitigating these effects is a challenge and is important to successfully place the cement slurry in the annulus and for the slurry to develop the required mechanical properties, such as compressive strength. In the present study, slurries were formulated to overcome gelation issues with the required compressive strength for successful zonal isolation. The slurries were designed in such a way that they can take up to 12% contamination by weight of water (bwow) of the MgCl2-based salts known as carnalite and tachyhydrite. Pertinent data that characterize performance of these slurries are presented in this paper.

Gas hydrates are known to occur in deepwater environments (low-temperature and high-pressure) at various locations across the globe. When they occur close to the sea bed, hydrates present challenges to drilling, completing, and producing in deepwater applications. Additionally, many operators now consider these as a potential resource when they occur deeper within the earth, and there is increased focus on feasibly producing methane from gas hydrates. Safety, environmental impact, and economic viability are the foremost challenges faced by the upstream oil and gas community to unleash the potential that these unconventional reserves hold for the future.Isolating the gas-hydrate-bearing zones by means of effective annular wellbore sealants is the prime factor that will contribute to the success of gas-hydrate campaigns. This paper addresses the current zonal isolation challenges likely to be encountered from the time drilling operation is completed until the plug and abandonment process is finished. With the considered lifecycle, a sealant system selection criteria based on commercially available technologies is proposed. While industry research on this front continues to progress, a holistic approach to designing a zonal isolation program to address the foreseeable challenges of unconsolidated formations, drilling-fluid removal in washouts, annular-sealant placement, battling lost circulation, prevention of hydrate destabilization, formation-fluid influx during the setting process, achieving good mechanical properties at low temperatures, and maintaining long-term sealing integrity throughout the life of the well is discussed and evaluated.The design approach involves (1) preliminary engineering sensitivity analysis to judge the effect of dominant parameters on sealant system design, (2) selection of commercially available, fit-for-purpose materials and laboratory testing, and (3) validation by means of confirmatory analyses. The approach presented is an incremental effort to help operators and industry researchers increase the productivity of gas-hydrate-bearing wells.

Long-term cement sheath integrity is important to maintain wellbore stability and effective zonal isolation. Various factors influence cement sheath integrity, such as effective placement of cement, mechanical and thermal stresses, and interaction with corrosive gases. Corrosive gases are known to chemically attack Portland cement. However, the challenge is designing a cement system that can sustain CO2 and H2S attack. Acid-gas-resistant systems are useful in various applications, including producers and CO2 injector wells. To understand how the cement sheath is affected by prolonged exposure to corrosive gases, detailed studies should be performed at different temperatures and pressure conditions. This paper documents a resilient cement system that was exposed to CO2 and H2S gas environments for a period of three months. For comparison purposes, a neat cement system was used as a reference and tests were conducted at 194 (90°C) and 284°F (140°C). X-ray density profiles obtained using tomography techniques were used to analyze samples. The cement samples responded differently to CO2 and H2S environments. Formation of CaCO3 on exposure to CO2 was evident and was reflected in X-ray density profiles. Conversely, leaching of neat cement was observed on exposure to H2S gas. In both cases, the resilient cement system specially designed for the work described proved to be a better option when compared to neat cement because the destruction was less prominent in the former case.

Polymeric viscosifiers are added to cement slurries for a variety of reasons, including prevention of particle settling and control of fluid loss, gas migration, and free-water. Many of these functions are critically important after the cement slurry has been placed behind the casing but before the setting of the cement. Some functions, such as particle-settling prevention, are also important during the pumping phase. Unfortunately, most of the viscosifying polymers suffer from thermal thinning at bottomhole temperatures, especially under shear. The amount of polymer required to maintain the required level of viscosity at elevated bottomhole temperatures causes excessive surface-slurry viscosification at ambient temperature. Pumping such slurries can require higher pump pressures, or in cases where formation breakdown pressure might be exceeded. This becomes a serious challenge when the window between the fracture pressure and the pore pressure of the formation is narrow. It would be a significant improvement to oilfield cementing technology to develop polymers that do not cause excessive slurry viscosification on the surface but gradually increase the slurry viscosity as it reaches downhole temperatures, with the maximum viscosity reached at the time the slurry becomes static behind the casing. This paper describes an economical chemical method, not based on encapsulation, for modifying biopolymers and their derivatives—for example, hydroxyethylcellulose, xanthan, and guar—that renders them insoluble in cement slurries at room temperature (RT). When the cement slurries are heated, the slurries develop viscosity, as reflected by rheological measurements. The method also provides for increased viscosification efficiency of the modified polymers because of the increased molecular weights of the modified biopolymer products. Synthesis details, slurry rheologies at different temperatures, and job-placement simulation details are presented. A possible reaction mechanism that is operative in the chemical-modification step is also discussed. Introduction Designing cement slurries to meet all the requirements for effective primary cementing requires the addition of many additives, some of which are functional in the slurry placement and some in the set cement. The additives that are functional in the slurry phase are added primarily to retard/accelerate the cement setting, optimize the rheological properties (by particle dispersion), prevent settling, provide fluid-loss control, and, in some cases, provide gas migration control. The latter three functions are accomplished by water-soluble, synthetic or biopolymer-based polymeric additives. Such polymeric additives, either because of their molecular weights or adsorption on cement particles, tend to excessively increase the surface-slurry viscosities if added in quantities sufficient to be effective at bottomhole circulating or static temperatures, referred to as BHCTs or BHSTs. This is often the case because most of the polymers undergo severe thermal thinning at BHCT or BHST. As a result of high initial slurry viscosities, either slow pumping rates or higher pump pressures are required for slurry placement, which could be problematic in cases where the fracture gradients of the formation are low or where the window between the fracture pressure and the pore pressure of the formation is narrow. In such cases, a compromise between surface and bottomhole viscosities is attempted by the addition of a dispersant and adjusting the viscosifier-to-dispersant ratio. This approach, at best, is poorly effective and requires extensive slurry testing because of the unintended influence of such additives on other properties, such as set retardation/acceleration, fluid loss, or strength development. Additionally, it is well established that, with additives requiring adsorption of cement particles to function, adding more of the additive will establish a competition between the additives for adsorption on the cement-particle surface. Depending on the relative adsorption capability of the additives, a strongly adsorbing additive might block the adsorption of a polymeric additive; thus, preventing manifestation of a property at desired timing. As an example, if a dispersant is strongly adsorbed on cement, it might prevent the adsorption or displacement by another polymer added for providing fluid-loss control (Plank et al. 2006). Similar

In recent years, the focus of the oil and gas industry has shifted toward the production of oil from deep and harsh environments. This has been possible because of advanced technologies coming available to the industry. However, challenges still remain in designing materials to withstand certain harsh environment. To satisfy the ever-increasing demand for oil and gas, the industry is tapping heavy oil, which poses unique challenges. Steam-assisted gravity drainage (SAGD) technique has made it possible to reduce the viscosity of heavy oil and render it mobile. In this technique, steam is injected through an injector well and down to the reservoir where temperature can be raised to 260°C (500°F). This reduces the viscosity of heavy oil but imposes severe thermal stresses on the cement sheath and casing. Such stresses could hamper zonal isolation and result in the release of steam to the surface. Designing a cement slurry for such applications is challenging of various aspects, such as mixability, pumpability, placement in the annulus, sheath resiliency, permeability, and compressive and tensile strength, that should be optimized to meet the technical, economical, and operational requirements. This paper details the designing of cement systems for SAGD application and its rigorous testing by simulating downhole conditions. A fit-for-purpose slurry was designed that is chemically stable at the downhole temperatures and able to withstand the thermal stresses. The optimized slurry was subjected to thermal cyclic loading in an experimental setup designed to simulate downhole conditions, and the performance was evaluated. The cement sheath was intact after being subjected to several thermal loadings. No cracking or de-bonding was observed. In this paper, the experimental setup, slurry design, testing procedure, and the results are discussed in detail. The discussions presented in the paper should help the industry in constructing and operating SAGD wells safely and economically.

The primary cement job is critical for a successful well completion. To achieve a successful well completion, effective and complete mud removal from the well is recommended (Ravi et al. 1992; Crook et al. 1980). Spacers and flushes are used to remove the mud from the well where cement is to be placed. As hydrocarbon resources become less accessible, operators are required to explore and produce from increasingly more difficult environments. Today, with the increasing number of HTHP wells being drilled, the design of robust yet stable spacers is becoming more critical. Various spacer fluids are available in the oil and gas industry to target effective mud removal. However, these spacers may not be suitable for HPHT wells. The performance of a spacer mainly depends on the rheology of spacer at the desired elevated temperature. In addition, a spacer should be compatible with the highly fit-for-purpose mud being used in the well. This paper compares the performance of Spacer A (advanced performance for weighted spacer) with Spacer B (previous technology weighted spacer) and Spacer C (low-cost, weighted spacer) in detail at various temperatures (80°F, 150°F, 250°F and 350°F) and their compatibility with various water-based muds (brine, clay type, and clay-free). The new spacer is unique in that the rheology (specifically, the yield point (YP)) remains constant over a wide range of temperatures (80°F up to 350°F). Typically, the spacer YP will fluctuate as a function of temperature. The YP of the fluid plays a critical role in the displacement of mobile mud and erosion of dehydrated mud. In addition, the new spacer is designed to provide accurate and reproducible results from the laboratory to the field, which minimizes testing within the laboratory and on the rig. Lastly, the spacer can be mixed in any equipment found in the oil-field, even mix-on-the-fly applications.