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A number of cementitious materials used for cementing wells do not fall into any specific API or ASTM classification.These materials include: Pozzolanic materials include any natural or industrial siliceous or silico-aluminous material, which will combine with lime in the presence of water at ordinary temperatures to produce strength-developing insoluble compounds similar to those formed from hydration of Portland cement. Typically, pozzolanic material is categorized as natural or artificial, and can be either processed or unprocessed. The most common sources of natural pozzolanic materials are volcanic materials and diatomaceous earth (DE). Artificial pozzolanic materials are produced by partially calcining natural materials such as clays, shales, and certain siliceous rocks, or are more usually obtained as an industrial byproduct. Pozzolanic oilwell cements are typically used to produce lightweight slurries.
Remedial cementing requires as much technical, engineering, and operational experience, as primary cementing but is often done when wellbore conditions are unknown or out of control, and when wasted rig time and escalating costs force poor decisions and high risk. Squeeze cementing is a "correction" process that is usually only necessary to correct a problem in the wellbore. Before using a squeeze application, a series of decisions must be made to determine (1) if a problem exists, (2) the magnitude of the problem, (3) if squeeze cementing will correct it, (4) the risk factors present, and (5) if economics will support it. Most squeeze applications are unnecessary because they result from poor primary-cement-job evaluations or job diagnostics. Squeeze cementing is a dehydration process.
Tao, Liang (Oil and Gas Technology Research Institute Changqing Oilfield Company, Petrochina Company Limited) | Zhao, Yuhang (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, China) | Zhang, Xiaozhuo (Oil and Gas Technology Research Institute Changqing Oilfield Company, Petrochina Company Limited) | Wang, Yanxing (Development Department, Changqing Oilfield Company, Petrochina) | Feng, Hongbo (Sichuan Yuesheng Oil and Gas Field Technical Service Co., Ltd. Changqing Branch) | Cao, Yujie (Oil and Gas Technology Research Institute Changqing Oilfield Company, Petrochina Company Limited) | Zhao, Zhihong (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, China)
Abstract Water imbibition is a key factor affecting the flowback system of shale gas wells after volume fracturing. This paper took shale samples from the Longmaxi formation (LF) in the Sichuan Basin as subjects, the experiments of shale water imbibition under different influencing factors were carried out. The water imbibition law was analyzed, and the shale water imbibition capacity was quantitatively characterized, the question if shut-down is necessary after volume fracturing of wells in shale gas reservoir has been answered objectively. The experimental results show that: according to imbibition saturation, the shale water imbibition can be divided into 3 periods, imbibition diffusion, imbibition transition and imbibition balance periods. Among them, the imbibition diffusion period is the main period for imbibition capacity rise. The shale sample with horizontal bedding had much larger imbibition capacity than the sample with vertical bedding. The initial micro-fractures provide percolation pathways for shale imbibition, making flow resistance drop and imbibition capacity increase rapidly. Imbibition capacities of the shale samples to different types of fluids in descending order were: deionized water, slick water, 2% KCl solution and kerosene. The micro-fracfures induced by shale hydration were mainly lamellation, with obvious directionality. Shale hydration can improve the fracturing effect of reservoir, resulting in the increase of porosity of 0.08-1.04 times and increase of permeability of 2.3-173.6 times. The study results can provide scientific basis for the optimization of flowback system of shale gas wells.
The reactions involved when cement is mixed with water are complex. It is important to understand these reactions or the cementing operation may not be successful. The reactions, however, are not independent of each other because of the composite nature of the cement particle and proximity of the phases. In cementing operations, the most important of these are Stages 1 through 3. Stage 1 dictates the initial mixability of the cement, and is attributed primarily to the aluminate and ferrite phase reactions. Stage 2 relates to the pumpability time, while Stage 3 gives an indication on setting properties and gel-strength development.
Summary Experiments on oil well cement (OWC) slurries were performed using the newly developed laboratory-scale wellbore simulation chamber (WSC). The WSC can simulate hydrostatic pressure reduction in the cemented annulus and possible gas migration under representative conditions. Forensic analysis shows that pressurized fluids can result in porous cement and gas channeling during cement slurry gelation. By analyzing the temperature history of hydrating cement using degree of hydration, the evolution of cement hydration was characterized for slurry designs cured at different hydration rates. This provides the opportunity to parameterize the slurry designs and other important factors associated with wellbore conditions. Introduction Gas migration into hydrating cement slurries, which requires costly remedial well treatments, is a major reason for well completion failures (Bonett and Pafitis 1996). The first documented research attempting to explain the gas communication by means other than leakage along interfaces was performed by Carter and Slagle (1972). It was found that gases and other fluids can invade the annular cement slurry as a result of hydrostatic pressure reduction during the early stage of cement hydration (short-term gas migration) (Nelson and Guillot 2006). Available theories regarding gas migration during this early hydration stage attribute the occurrence of gas migration to an ineffective initial hydrostatic head, an unstable cement slurry design, fluid loss after cement placement, and weak bonding at interfaces as cement hydrates. Gases do not invade the cement slurry if the slurry pore pressure remains above the formation gas pressure (Cheung and Beirute 1985). It was found that hydrostatic pressure in the cement column declines shortly after cement placement (Brufatto et al. 2003). Once the hydrostatic pressure decreases to a point below the formation gas pressure, gas migration may occur if the cement matrix has not yet developed enough strength to withstand gas invasion. In the Minerals Management Service reporting system, nearly all post-cementing gas flows occurred 3 to 8 hours after cementing jobs (Kellingray 2007). Cement hydration involves changes in both the chemical and physical properties of the cement slurry. Due to the difficulties in modeling time-dependent properties of hydrating cement slurry, the petroleum industry uses empirical approaches when designing cement slurries able to reduce the risk of gas migration (Kremieniewski and Rzepka 2018).
The interpreted pressure transient test is a primary source of dynamic reservoir data. Tests on oil and gas wells are performed at various stages of drilling, completion, and production. Most pressure transient tests can be classified as either single-well productivity tests or descriptive reservoir tests. The pressure-flow convolution involves simultaneous bottomhole flow rate and pressure measurements to correct for the variations of bottomhole pressure caused by flow rate fluctuations during drawdown tests. When software deconvolution operators are used, trial and error is required to convolve a flow-rate schedule with a pressure function that approximates the true constant rate-equivalent pressure function, thus reproducing the measured pressures.
Despite the lack of freshwater resources in the Arabian peninsula, fresh water is still used in unconventional-resource operations there. Seawater, however, is plentiful and could substitute for fresh water. The high salinity of seawater raises many chemical challenges in developing design criteria for fracturing fluids. The oil and gas industry faces many challenges, including the availability of fresh water for making fracturing fluids, especially in the Arabian peninsula and other arid regions. Using seawater to make fracturing fluid can help address several obstacles and reduce costs.
Summary The performance of oil-well cement is altered if contaminated by spacers. Very few studies in the literature are found on this topic, in particular for newly developed microemulsion spacers. Therefore, it is worth investigating the properties of cement contaminated with spacers. In this study, material characterization techniques including chemical shrinkage, ultrasonic pulse velocity (UPV), thermogravimetric analysis (TGA), scanning electron microscopy (SEM), and nitrogen adsorption (NAD) were used to study the hydration and microstructure of contaminated cement. Results showed that the studied microemulsion spacer was less compatible with the cement slurry than the conventional one. The microemulsion spacer has complex effects on cement hydration: it slightly enhances hydration for the low dosage but can retard hydration at the early ages and accelerate hydration in the later ages with the increase of dosage. The conventional spacer caused early acceleration of cement hydration but had no effect at later ages. The presence of spacers in the cement slurry decreases the compressive strength and creates a more complex microstructure than is found for the neat cement. All these effects with the studied microemulsion spacer are worse than with the conventional spacer. Therefore, the presence of a microemulsion spacer in a cement slurry may cause long-term durability issues compromising the downhole zonal isolation. Introduction During the course of drilling operations, cement is used for the purpose of sealing the casing, stabilizing a zone where substantial drilling-fluid losses are occurring, and setting a kickoff plug for the well (Nelson and Guillot 2006). Long-term zonal isolation requires cement to be properly placed and to provide low permeability, mechanical durability, and adaptability to changing wellbore conditions. However, the success of well cementing is difficult to achieve when nonaqueous fluids (NAFs) are used as lubricants in natural gas and oil well-drilling operations (Nelson and Guillot 2006; Caenn et al. 2016; Hua et al. 2016). NAFs can change the casing surface condition from water-wet to oil-wet, which decreases the cement's compressive and shear strengths and the bond between cement and casing (Aughenbaugh et al. 2014; Li et al. 2015; Zhang et al. 2016). Failure to effectively displace NAFs from the wellbore and to allow water-wetting of the casing and formation before cementing can be costly. To remove NAFs, a cement preflush spacer is designed to effectively separate the cement from any NAFs during displacement while simultaneously water-wetting the casing and formation for optimizing bonding (Quintero et al. 2008; Christian et al. 2009; Darugar et al. 2010). Conventional spacers typically consist of water, alcohol, and/or surfactants (to make them compatible with both the drilling fluid and the cement slurry), and a densifier, such as barite.
Summary Quantifying wettability of organic‐rich mudrocks is important for reliable formation evaluation, optimizing production, predicting water/hydrocarbon production, and selection of appropriate fracture fluids. Recent publications suggest that kerogen wettability can vary as a function of thermal maturity, ranging from water‐ to hydrocarbon‐wet at low to high thermal maturities, respectively. However, clay minerals tend to preferentially be water‐wet. It is therefore important to determine which of these constituents have a dominant contribution to overall wettability of the rock. To answer this question, we introduce methods to quantify the relative water‐adsorption capacities of clay minerals, kerogen, and organic‐rich mudrocks at different thermal‐maturity levels. We started with isolating kerogen from organic‐rich mudrock samples using chemical and physical separation methods and synthetically matured them to different thermal‐maturity levels. We then prepared synthetic organic‐rich mudrock samples by mixing known quantities of clay minerals, nonclay inorganic minerals, and kerogen. We then performed water‐vapor adsorption measurements on pure clay minerals, pure kerogen samples, and synthetic organic‐rich mudrock samples under controlled humidity conditions. Nuclear magnetic resonance (NMR) measurements were then used to quantify the volume of water adsorbed on clay minerals and organic‐rich mudrock samples. We used the flotation test to qualitatively assess the wettability of the synthetic organic‐rich mudrocks. Water‐vapor adsorption experiments showed that the volume of water adsorbed on the surface of nonheated kerogen samples at low thermal maturities is 5.31 mL/100 g, which decreases significantly to 0.09 mL/100 g when the kerogen sample is heat‐treated to 450°C. The results can be attributed to strong attraction between the oxygen content in kerogen and water at low thermal maturities. We quantified the water‐adsorption capacity of kerogen samples heat‐treated at 450°C and found that volume of water adsorbed decreases with an increase in thermal maturity both in the presence and absence of bitumen. In the case of synthetic organic‐rich mudrock samples, we found that the volume of water adsorbed in samples at higher thermal maturity decreases by 16% compared with organic‐rich mudrocks at low thermal maturity at the same concentration of nonswelling clay minerals. Results from the flotation test showed that the oil‐wettability of the synthetic organic‐rich mudrock samples increases as its thermal maturity decreases, with a hydrogen index (HI) of 328 to 54 mg hydrocarbon/g organic carbon (mg‐HC/g‐OC). Results confirmed that kerogen and its geochemistry can have a significant influence on the overall wettability of organic‐rich mudrocks even at low concentrations of 4 wt%. The outcomes of this paper can contribute to a better understanding of the parameters affecting wettability of organic‐rich mudrocks and are promising for in‐situ assessment of their wettability. This can potentially contribute to improved understanding of flow mechanisms in organic‐rich mudrocks, which control hydrocarbon/water production.