This article describes the chemical make-up and application of the types of gels most commonly used in conformance improvement. Oilfield conformance improvement gels come in a wide range of forms and chemistries. Table 1 provides an overview of various conformance improvement gels. CC/AP gels have an exceptionally robust gel chemistry and are highly insensitive to oilfield and reservoir interferences and environments. They are also applicable over an exceptionally broad pH range. As a result, these gels, when properly formulated, are applicable to the acidic conditions associated with CO2 flooding for which most earlier oilfield polymer gels did not function well.
Two forms of derivatized cellulose have been found useful in well-cementing applications. The usefulness of the two materials depends on their retardational character and thermal stability limits. This is commonly used at temperatures up to approximately 82 C (180 F) for fluid-loss control, and may be used at temperatures up to approximately 110 C (230 F) BHCT, depending on the co-additives used and slurry viscosity limitations. Above 110 C (230 F), HEC is not thermally stable. HEC is typically used at a concentration of 0.4 to 3.0% by weight of cement (BWOC), densities ranging from 16.0 to 11.0 lbm/gal, and temperatures ranging from 27 to 66 C (80 to 150 F) BHCT to achieve a fluid loss of less than 100 cm3 /30 min.
The goal was to search for a replacement of CaCl2 which presents the most widely used accelerator for oil well cement used in cold and arctic environments and sometimes in deepwater drilling. For this purpose, novel calcium silicate hydrate (C-S-H) nanoparticles were synthesized and tested. The C-S-H was synthesized by the precipitation method in an aqueous solution of polycarboxylate (PCE) comb polymer which is widely used as concrete superplasticizer. The resulting C-S-H-PCE suspension was tested in the UCA instrument as seeding material to initiate the crystallization of cement and thus accelerate cement hydration as well as shorten the thickening time at low temperature. It was found that in PCE solution, C-S-H precipitates first as nano-sized droplets (Ø ~20 - 50 nm) exhibiting a PCE shell. Following a rare, non-classical nucleation mechanism, the globules convert slowly to nanofoils (HR TEM images: l ~ 50 nm, d ~ 5 nm) which present excellent seeding materials for the formation of C-S-H from the silicate phases C3S/C2S present in cement. Thickening time tests performed at + 4 °C in an atmospheric consistometer revealed stronger acceleration than from CaCl2 while very low slurry viscosity was maintained, as was evidenced from rheological measurements. Accelerated strength development was checked on UCA cured at + 4 °C and under pressure, especially the wait on cement time was significantly reduced. Furthermore, combinations of C-S-H-PCE and HEC as well as an ATBS-based sulfonated fluid loss polymer were tested. It was found that this C-S-H- based nanocomposite is fully compatible with these additives. The novel accelerator based on a C-S-H-PCE nanocomposite solves the problems generally associated with CaCl2, namely undesired viscosity increase, poor compatibility with other additives and corrosiveness against steel pipes and casing.
Formation of scales in near-wellbore reservoir/downhole and production systems can lead to production loss, system integrity and reliability degradation, and fouling of device and equipment. The mitigation and remediation of oilfield depositions can be difficult and costly. Better understanding of the key factors impacting scale dissolution, such as temperature and pH will benefit scale mitigation practices. Most of the research and investigation of silicate dissolution for example are based on low temperature experiences (e.g., <100 °C). Strong acids such as concentrated HCl, HF and aqua regia may not be applicable for field application.
In this study, field depositions with various scale types such as silicates, carbonate, sulfides are characterized and used for studying effects of pH, temperature and solvent on their dissolution. Experiments with oilfield scale deposit samples including silicates were conducted with high temperature thermal aging cells at temperature range >100 °C and pH from 6 – 8. Dissolution test with field scale samples were also conducted under ambient conditions. Various solvents including xylene, HCl and acetic acid were used in the test.
To summarize the results, decreasing temperature has limited effect on dissolution of magnesium silicates, but improves dissolution of calcite and anhydrite which coexist with the field sample. Decreasing pH improves the dissolution of magnesium silicate and calcite. Total amount of dissolved silicates can increase significantly due to appropriate pH decrease. Solution pH is increased dramatically due to the formation of hydroxyl ions during the dissolution process. The reaction for dissolution of metal silicate scale is proposed based on observation and results in the study. More fine particles are produced after dissolution and suspended in solution for at least 15 minutes, which makes solid mitigation possible by applying proper agitation. Oilfield deposits can include a variety of components, and appropriate scale sample characterization should be utilized for selection of mitigation/remediation approaches.
This paper provides novel information of oilfield scale dissolution (including silicate scale) at high temperature by using field applicable treatment approaches. Results lead to better understanding of silicate dissolution at various pHs and temperatures, and required conditions for successful mitigation and remediation of oilfield scale deposits
Ahdaya, Mohamed Saad (Missouri University of Science and Technology) | Imqam, Abdulmohsin (Missouri University of Science and Technology) | Jani, Priyesh (Missouri University of Science and Technology) | Fakher, Sherif (Missouri University of Science and Technology) | ElGawady, Mohamed (Missouri University of Science and Technology)
One of the most important steps in drilling and operation completion is oil well cementing to provide wellbore integrity. Cementing is usually performed in the oil industry using conventional Portland cement. Even though Portland cement has been used for many years, it has several drawbacks, including operational failures and severe environmental impacts. Fly ash based geopolymer cement has been recently investigated as a low-cost, environmentally friendly alternative to Portland cement. This research develops a novel formulation of Class C fly ash based geopolymer and investigates its applicability as an alternative to Portland cement in hydrocarbon well cementing. Twenty-four variations of fly ash Class C based geopolymers were prepared, and by comparing several of their properties using API standard tests, the optimum geopolymer formulation was determined. The ratios of alkaline activator to fly ash that were used are 0.2, 0.4, and 0.8, along with different ratios of sodium silicate to sodium hydroxide, including 0.25, 0.5, 1, and 2. Multiple sodium hydroxide concentrations were used, including 5, 10, and 15 molarity. The selection of the optimum formulation was based on five different tests, including rheology, density, compressive strength, fluid loss test, and stability tests (sedimentation test and free fluid test). Then, a comparison between the optimum mix design and Portland cement was conducted using the same tests. Based on our results, increasing sodium hydroxide concentration resulted in an increase in compressive strength and showed a slight decrease in the plastic viscosity. However, increasing in the alkaline activator to fly ash ratios increased plastic viscosity, and thus the pumpability of the slurry was reduced. Increasing the sodium silicate to sodium hydroxide ratio significantly decreased the fluid loss. The optimum design of geopolymer, which had lower fluid loss, 93 ml after 30 minutes, sufficient compressive strength, 1195 psi, and an acceptable density, 14.7 lb/gal, and viscosity, 50 cp, was selected. Compressive strength of the optimum design showed better results than neat Portland cement. Unlike neat Portland cement, which needs fluid loss additives, the new formulation of geopolymer investigated in this study showed fluid losses lower than 100 ml after 30 min when tested using a low-pressure, low-temperature filtrate loss tester. The higher mechanical strength of geopolymer using fly ash Class C compared to Portland cement is very promising for achieving long-term wellbore integrity goals and meeting regulatory criteria for zonal isolation. The rheological behavior, compressive strength, and fluid loss tests results indicate that fly ash Class C based geopolymer has the potential to be an environmentally friendly alternative to Portland cement when cementing oil wells.
Abubakar Umar, Abubakar (Centre of Research in Enhanced Oil Recovery, Universiti Teknologi PETRONAS) | Mohd Saaid, Ismail (Centre of Research in Enhanced Oil Recovery, Universiti Teknologi PETRONAS) | Adebayo Sulaimon, Aliyu (Department of Petroleum Engineering, Universiti Teknologi PETRONAS) | Mohd Pilus, Rashidah (Department of Petroleum Engineering, Universiti Teknologi PETRONAS) | Amer, Nurul Asna (Centralized Analytical Laboratory, Universiti Teknologi PETRONAS) | Halilu, Ahmed (Department of Chemical Engineering, Universiti Malaya.) | Mamo Negash, Berihun (Department of Petroleum Engineering, Universiti Teknologi PETRONAS)
Water-in-oil petroleum emulsions were prepared using response surface methodology (RSM) based on box-Behnken design (BBD). The emulsions were prepared using a treated Malaysian offshore crude oil, where the saturates, aromatics, resins and asphaltenes (SARA) of the crude oil were extracted using a modified SARA analysis. Other native solids, wax and asphaltenes extracted from oilfield emulsions and other crude oils were used as the emulsifying agents. In this paper, we focus on the characterization of some oilfield solids extracted from Malaysian offshore fields and further investigated their potentials to stabilize petroleum emulsions. The effects of the solids alone, and in combination with asphaltene/resin and wax were studied using statistical methods and the stabilities of the emulsions examined using a Turbiscan optical analyzer. The main advantage of Turbiscan is to obtain a faster and more accurate detection of destabilization phenomena in non-diluted emulsion than can be detected by the naked-eye (observation), especially for an opaque and concentrated dispersion system. The sample characterizations were conducted with FTIR, TGA, FESEM/EDX, XRF and XRD. Results showed that the major native solids present in the samples were paraffins and calcium carbonate. Further analysis revealed that the solids by themselves do not significantly contribute to emulsion stability. However, in the presence of asphaltene/resin compounds, the prominent solids such as paraffins and calcium carbonate enhance the stability of the emulsion irrespective of asphaltene/resin concentrations.
This study presents a numerical modeling of a sodium silicate gel system (inorganic gel) to mitigate the problem of excess water production, which is promoted by high heterogeneity and/or an adverse mobility ratio. A numerical model of six layers was represented by one quarter of five spot pattern with two thief zones. CMG-STARS simulator was used that has the capabilities of modeling different parameters. The gelation process of this gel system was initiated by lowering the gelant's pH, and then the reaction process proceeded, which is dependent on temperature, concentration of the reactant, and other factors. An order of reaction of each component was determined and the stoichiometric coefficients of the reactants and product were specified. The purpose of this study is to develop a thorough understanding of the effects of different important parameters on the polymerization of a sodium silicate gel system.
This study was started by selecting the optimum gridblock number that represents the model. A sensitivity analysis showed that the fewer the number of gridblocks, the better the performance of the gel system. This model was then selected as a basis for other comparisons. Different scenarios were run and compared. The results showed that the gel system performed better in the injection well compared to the production well. In addition, the treatment was more efficient when performed simultaneously in injection and production wells. Placement technology was among the parameters that affected the success of the treatment; therefore, zonal isolation and dual injection were better than bullhead injection. Lower activator concentration is more preferable for deep placement. Pre-flushing the reservoir to condition the targeted zones for sodium silicate injection was necessary to achieve a higher recovery factor. Moreover, different parameters such as adsorption, mixing sodium silicate with different polymer solutions, effects of temperature and activation energy, effects of shut-in period after the treatment, and effects of reservoir wettability were investigated. The obtained results were valuable, which lead to apply a sodium silicate gel successfully in a heterogeneous reservoir.
The formation of silica and silicate scales caused troublesome issues in various water-handling systems, including steam generators, geothermal wells, and waste-water disposal systems. Recently, a produced water with over 300 ppm of silica, and a spent brine off the strong acid cation (SAC) softeners containing high levels of calcium (Ca), barium (Ba), and magnesium (Mg) were commingled in the production wells. The mixing of these two waters induced silicate as well as other scales, including calcite, barite, etc. In order to provide effective scale inhibition when these waters are mixed, effective scale inhibitors for both silicate and other scales were requested for evaluation.
In this paper, scale inhibitor chemistries for preventing both silica/silicate and other scales were reviewed and the possible synergistic effects were assessed by Design of Experiment (DOE) software. DOE is a systematic method to determine the relationship between several factors, i.e. various chemistries and the performance of formulations under designed application conditions. Selected chemicals were formulated for control of both silica/silicates and other scales, and their performances were evaluated by a Kinetic Turbidity Test (KTT). The KTT is a novel laboratory test method using an Ultraviolet-Visible (UV-Vis) spectrophotometer to monitor the formation of scales at various dosages of tested products. Bottle tests were also conducted for the comparison of inhibition performance.
Based on the lab testing results from the KTT and the bottle tests, the combined products exhibited good scale inhibition performance for both silicate and other scales. The product was recommended for field applications. Subsequent field applications of this product have provided the desired scale control.
This paper presents the laboratory testing data for scale inhibitor selection for the combination products on both silica/silicate control and other scale control by using the efficient performance evaluation method. It also provides an effective product formulation approach for finding synergetic effects of different products. Successful scale inhibitor implementations in the field applications are also presented in this paper. Both laboratory and field testing results show a good case history for the optimization of the silica/silicate and other scale treatment.
ABSTRACT: Hydraulic fracturing operations favour mechanically weak horizons over soft lithologies for fracture propagation; thus, accurate assessment of the elasto-plastic properties of these bedded layers is crucial for deliverability. Moslow, Adams, & Terzuoli, 2016 proposed the deliverability of hydrocarbons in the Montney shale play to be related to the mechanical contrast of biostromes with surrounding siltstones; however, the logistics of determining these mechanical properties are difficult. This work aims to characterize the constituent biogenic and silt rich phases present in the lower Triassic Montney formation through micromechanical testing. Petrographic thin sections (~30 μm thick) are prepared from Montney shale core trimmings from a silt rich and a bioclast rich horizon to quantify the elastic and plastic deformations of the material at a micromechanical scale. Nanoindentation combined with photomicrography and scanning electron microscopy with energy/wave dispersive spectrometry (SEM: EDS/WDS) are used to analyze the mechanical properties such as fracture toughness and stiffness of the samples along the view inplane with bedding, where mechanical properties out of plane are to be incorporated in future works. The observed micromechanical behaviour stemming from structural/mineralogical causes will ultimately serve to better understand reservoir fracability in difficult geomechanical sampling conditions.
The rapidly developing state of hydraulic fracturing technologies demand a high quality of quantitative assessment of target horizons for deliverability; where deliverability can vary depending on various hydrogeological regimes and production methods. Thus, one of the intrinsic geomechanical interests lies on the determination of fracability. As such, fracability is defined as a function of various mechanical properties including brittleness, fracture toughness, and elastic modulus which have been used in the past to derive a measure of fracability and brittleness indices (Bai, 2016; Cho & Perez, 2014; Jin, Shah, Roegiers, & Zhang, 2015; Yuan et al., 2017).
Reevaluation of the appropriateness of past methods of defining brittleness such as the work by Jin et al., 2015, provided insight on minimizing the total energy input in stimulation processes, but have not commented on the role of structural components promoting fracability in the Lower Montney as noted by Moslow et al., 2016. The geologic logging and interpretation conducted in Moslow et al., 2016 makes note of the highly alternating stratigraphic composition of bioclastic zones with bituminous siliclastic layers and proposes the possibility of high deliverability associated with contrasting ductile and brittle geomechanical behavior. This to be a Claraia biostrome noted by Moslow et al., 2016, informs a degree of bioclastic homogeneity and thus implied mechanical characteristics. However, geomechanical testing to confirm the hypothesis was not available due to challenging sample retrieval conditions of high in-situ stress conditions (~2100 m depth) combined with the scale of heterogeneity present (~mm scale laminations of bioclasts).
ABSTRACT: Due to scarcity of the natural reservoir core material, artificial sandstones are prepared instead. In this study, sodium silicate solution was used as the cementing agent for a quartz sand material. The cylindrical molded soft sand-cement mixtures were placed in the specially designed positive pressure gas vessel, where the hardening of the cementious material takes place as the chemical reaction between carbon dioxide and the silicate solution progresses. The distribution and the physical form of the cementious materials inside the intergranular space between the sand particles were evaluated by the means of Scanning Electron Microscopy and the Energy Dispersive Spectroscopy. Cement dosage in relation to different strength levels of the natural sandstone reservoirs is assessed and both the macroscopic and microscopic analyses present the characteristics of bond breakage and its effect on the plastic deformation of the samples. Shearing and compressional behavior of the artificial sandstones is studied at different stress levels. The temperature effect on the cement structure recrystallization and on the alteration of the stress-strain behavior is investigated.
Artificial sandstone preparation methodology implies different purpose, and subsequently different cement type, its content and preparation conditions. Some authors use techniques involving mixing sand, Portland cement and water (Rios et al., 2014), (Younessi et al., 2013) or mixing sand, Portland cement and calcium chloride (Alvarado et al., 2012); others fire the clay and sand mixture (Maccarini, 1987), (Hezmi et al., 2009), (Shabdirova et al., 2016) for clay-rich sandstones fabrication.
Another group of authors try to replicate the diagenesis of calcite cement by the CIPS (Calcite In-Situ Precipitation) (Tatzki, 2003), (Ismail et al., 2000). The method used in this work is adopted from (David et al., 1998), (Holt et al., 1993), (Tronvoll et al., 1997) with some modifications.
The goal of the current work was to create a synthetic sandstone which is close to the ultra-weak formations (Tronvoll et al., 1997), (Wu et al., 2016) in terms of mechanical parameters, i.e. unconfined compressive strength less than 3.5 MPa (Wu et al., 2016). In order to replicate the reservoir rock of interest for further experimental study of sand production, the artificial sandstone needed to be weak in compressive strength with high porosity and permeability parameters.