|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Dispersants, also known as friction reducers, are used extensively in cement slurries to improve the rheological properties that relate to the flow behavior of the slurry. Dispersants are used primarily to lower the frictional pressures of cement slurries while they are being pumped into the well. Converting frictional pressure of a slurry, during pumping, reduces the pumping rate necessary to obtain turbulent flow for specific well conditions, reduces surface pumping pressures and horsepower required to pump the cement into the well, and reduces pressures exerted on weak formations, possibly preventing circulation losses. Another advantage of dispersants is that they provide slurries with high solids-to-water ratios that have good rheological properties. This factor has been used in designing high-density slurries up to approximately 17 lbm/gal without the need for a weighting additive.
Well preparation includes many activities to ensure that the well is completed properly. Some of these items and activities include appropriate drilling practices, cleanliness, completion fluids, perforating, perforation cleaning, acidizing, and/or specifications for rig and service company personnel. The productivity of a cased- or openhole gravel-packed completion is determined in part by the condition of the reservoir behind the filter cake, the quality of the filter cake, and the stability of the wellbore. Given this, it can be said that the completion begins when the bit enters the pay. Thus, it follows that the goal of drilling is to maintain wellbore stability while minimizing formation damage. But, for whatever reason, instability affects both cased- and openhole completions because it can cause loss of the wellbore. Thick cement sheaths in washed-out sections result in poor to no perforation penetration and the lack of cement can make sand placement difficult. Hole collapse can prevent running screens to the bottom of the hole. Failure, in the form of fracturing or collapse, can stop an openhole gravel pack, should failure occur while the pack is in process.
Abstract This work presents a matrix acidizing formulation which comprises a salt of monochloroacetic acid giving a delayed acidification and a chelating agent to prevent precipitation of a calcium salt. Results of dissolution capacity, core flood test and corrosion inhibition are presented and are compared to performance of 15 wt% emulsified HCl. Dissolution capacity tests were performed in a stirred reactor at atmospheric pressure using equimolar amounts of the crushed limestone and dolomites. Four different chelating agents were added to test the calcium ion sequestering power. Corrosion tests were executed using an autoclave reactor under nitrogen atmosphere at 10 barg. Core flood tests were performed to simulate carbonate matrix stimulation using limestone cores. It was found that the half-life time of the hydrolysis reaction is 77 min at a temperature of 100 °C. Sodium gluconate and the sodium salt of D-glucoheptonic acid were identified to successfully prevent the precipitation of the reaction product calcium glycolate at a temperature of 40 °C. Computed Tomography (CT) scans of the treated cores at optimum injection rate showed a single wormhole formed. At 150 °C an optimum injection rate of 1 ml/min was found which corresponds to a minimum PVBT of 6. In addition, no face dissolution was observed after coreflooding. Furthermore, the corrosion rates of different metallurgies (L80 and J55) were measured which are significantly less than data reported in literature for 15wt% emulsified HCl. The novelty of this formulation is that it slowly releases an organic acid in the well allowing deeper penetration in the formation and sodium gluconate prevents precipitation of the reaction product. The corrosivity of this formulation is relatively low saving maintenance costs to installations and pipe work. The active ingredient in the formulation is a solid, allowing onsite preparation of the acidizing fluid.
Abstract As our industry is tapping into tighter carbonate reservoirs than in the past, completion techniques need to be improved to stimulate the low-permeability carbonate formation. Multistage acid fracturing technique has been developed in recent years and proved to be successful in some carbonate reservoirs. A multistage acid fracturing job is to perform several stages of acid fracturing along a horizontal well. The goal of acid fracturing operations is to create enough fracture roughness through differential acid etching on fracture walls such that the acid fracture can keep open and sustain a high enough acid fracture conductivity under the closure stress. In multistage acid fracturing treatments, acid flow is in a radial flow scenario and the acid etching process can be different from acid fracturing in vertical wells. In order to accurately predict the acid-fracture conductivity, a detailed description of the rough acid-fracture surfaces is required. In this paper, we developed a 3D acid transport model to compute the geometry of acid fracture for multistage acid fracturing treatments. The developed model couples the acid fluid flow, reactive transport and rock dissolution in the fracture. We also included acid viscous fingering in our model since viscous fingering mechanism is commonly applied in multistage acid fracturing to achieve non-uniform acid etching. Our simulation results reproduced the acid viscous fingering phenomenon observed from experiments in the literature. During the process of acid viscous fingering, high-conductivity channels developed in the fingering regions. We modeled the acid etching process in multistage acid fracturing treatments and compared it with acid fracturing treatments in vertical wells. We found that due to the radial flow effect, it is more difficult to achieve non-uniform acid etching in multistage acid fracturing treatments than in vertical wells. We investigated the effects of perforation design and pad fluid viscosity on multistage acid fracturing treatments. We need to have an adequate number of perforations in order to develop non-uniform acid etching. We found that a higher viscosity pad fluid helps acid to penetrate deeper in the fracture and result in a longer and narrower etched channel.
Abstract Advances in digital technologies have the potential to enhance model predictive capability and redefine its boundaries at various scale. Digital oil with accurate representation of atomistic components is a powerful tool to analyze both macroscopic properties and microscopic phenomena of crude oil under any thermodynamic conditions. Digital oil model presented in this paper is the key input in molecular chemistry modeling for designing chemical enhanced oil recovery formulation. Hence, it is constructed based on a fit-for purpose strategy focusing in oil components that have large contribution to microemulsion stability. Complete crude oil composition could comprise over 100,000 components. Lengthy simulation time is required to simulate all crude oil components which is impratical, despite the challenges to identify all crude oil components experimentally. Therefore, we established a practical experimental strategy to identify key crude oil components and constructed the digital oil model based on surrogate components. The surrogate components are representative molecules of the volatiles, saturates, aromatics and resins. Two-dimensional digital oil model, with aromaticity on one axis, and the size of the molecules on the other axis was constructed. We developed algorithm to integrate nuclear magnetic resonance response with architecture of the molecular structure. A group contribution method was implemented to ensure reliable representation of the molecular structure. We constructed the digital oil models for a field in Malaysia Basin. We validated the physical properties of the digital oil model with properties measured from experiment, predicted from molecular dynamics simulation and calculated from quantitative property-property relationship method. Good agreement was obtained from the validation, with less than 5% and 13% variance in crude density and Equivalent Alkane Carbon Number respectively, indicating that the molecular characteristic of the digital oil model was captured correctly. We adopted the digital oil model in molecular chemistry modeling to gain insights into microemulsion formation in chemical enhanced oil recovery formulation design. Digital oil is a robust tool to make predictions when information cannot be extracted from experimental data alone. It can be extended for engineering applications involving processing, safety, hazard, and environmental considerations.
Biofuels are an alternative to fossil fuels that are produced from fats derived from living organisms. One source of biofuel that is being explored more thoroughly in recent years is microalgae. The bio substance can be turned into crude oil, which can then be used to create biodiesel, biobutanol, biogasoline, methane, ethanol, or jet fuel. In 1942, European scientists Richard Harder and Hans von Witsch proposed the mass cultivation of diatoms to produce fat, which was urgently needed because of World War II. Government researchers began exploring algae as a source of fuel in 1978 and continued experiments through 1996. Algae can be grown under multiple conditions, including those unfavorable to other plants.
Since the most common use of matrix acidizing is the removal of formation damage, it is important to understand the nature of the damage that exists so that an appropriate treatment can be designed. Well testing and well test analysis generate a skin factor and well completion efficiency. This is insufficient alone for formation damage diagnosis. Well performance analysis has provided a beneficial tool to identify the location and thickness of damage at flow points in the near wellbore area. Models of flow into perforations and gravel-packed tunnels provide a way to relate the location and severity of damage to the completion procedure that preceded it.
In formations with over 1% carbonate, an HCl or acetic acid preflush dissolves the carbonate to prevent waste of HF acid and formation of the insoluble precipitate calcium fluoride. Calcium and sodium chloride workover brine also must be flushed away from the wellbore with HCl acid or ammonium chloride brine. Preflushes also displace and isolate incompatible formation fluids (either brine or crude oil). Higher concentrations of ammonium chloride ( 3%) are recommended where swellable smectite and mixed layer clays are present. For successful HF acidizing, more than 120 gal/ft of HF/HCl acid is usually required.
You've decided that your well is a good candidate for acidizing, assessed the formation, designed the treatment, prepared the well and equipment, so now you're ready to conduct the treatment. This page describes both the process and things you should be doing during and immediately after the treatment. The main acid job should be circulated in place with HCl acid placed across the formation before the packer is set or before the bypass valve is closed. All perforations should be covered by acid before injection starts. Injection should start at a predetermined injection rate and the pressure observed to determine the condition of the wellbore.
Environmental hazards can be reduced or prevented by the proper choice of chemical additives at optimum concentrations. Pressure tests are performed with water or brine to ensure the absence of leaks in pressure piping, tubing, and packer. Leaks on the surface can endanger service personnel, and subsurface leaks can cause subsequent corrosion of tubing and casing in the annulus. Anyone around acid tanks or pressure connections should wear safety goggles for eye protection. Those handling chemicals and valves should wear protective gauntlet-type, acid-resistant gloves.