|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Abstract Formation damage resulting from organic and inorganic depositions, such as calcium carbonate, asphaltene and paraffin, is one of the most commonly encountered types of damage in the oil and gas industry. These depositions are usually associated with a decrease in crude productivity, accelerated failure of production completions, such as from electric submersible pumps (ESPs), and less footage coverage while running with production and flow profile logging tools. The major concern highlighted is the increased probability of having more organic deposits in the wellbore as a result of the increased scale of the inorganic deposits. A thick, heterogeneous sludge mix of hydrocarbons and solid materials is a critical subject for characterization and solubility measurements. Analyzed deposit samples were collected either while running with production logging tools, when pulling out a failed ESP, or when lowering the completion equipment. The hydrocarbon phase was removed by organic solvent and the precipitated solid materials were collected for a lab analysis and solubility test. The solid phase analyses included X-ray diffraction (XRD) analysis and scanning/transmission electron microscopy (SEM and TEM). The composition of organic deposit samples was investigated using saturates, aromatics, resins, and asphaltenes (SARA) characterization, Fourier transform infrared analysis (FTIR) and Fourier transform ion cyclotron resonance mass spectrometry (FTMS). The sludge sample solubility tests were conducted over a variety of organic solvents at different temperatures, up to 300°F with a solid mass/liquid volume ratio of 1:10. The paper presents a typical analysis procedure of organic deposits collected from downhole equipment. The XRD analysis of solid debris materials (inorganic) present in collected sticky materials samples showed that the materials contained mainly carbonate compounds; for instance, calcite-CaCO3, dolomite-CaMg(CO3)2, and Halite-NaCl. These materials were completely soluble in acids like 15 wt% of HCl at reservoir conditions. Calcite scale would have been a problem in cases where the calcium content exceeded 12,000 mg/L. Low solubility results were obtained with static reaction of organic solvents recipes with the sticky materials around 17 to 50 wt%. This, in turn, increased solubility up to 98% as observed from the reaction in dynamic conditions.
Abstract Asphaltene precipitation and deposition occur in the reservoir, near-wellbore, inside the tubing, and production facilities during primary, secondary, or tertiary production. As more water-flooded oil fields produce under miscible gas flooding, this problem becomes more common around the world. If asphaltene deposition occurs in the reservoir or wellbore, it can severely affect the economics of the field in terms of production loss, intervention cost, and the requirement for chemical additives, if necessary. In some severe cases, intervention would be impossible and side-track well needs to be drilled. Hence, the best strategy for oil production in asphaltenic reservoirs is to control asphaltene precipitation and deposition through prevention and remediation jobs to minimize the number of well shut-ins, the downtime of the wells, and the associated cost. In this paper, we reviewed the common asphaltene prevention and remediation techniques along with their pros and cons. Since removing asphaltene deposits from the problematic wells is relatively expensive and sometimes requires substantial downtime of the well, we focused on one of the prevention techniques (i.e., continuous solvent injection through capillary injection string), which has become more popular, to control asphaltene precipitation in the wellbore. We obtained the physical properties of an aromatic solvent from literature and then characterized it as a component to be used with PC-SAFT EOS. Subsequently, we used the in-house wellbore model to evaluate the effectiveness of the continuous solvent injection with different injection rates on preventing asphaltene precipitation and deposition along the wellbore.
Abstract In the last few years, large efforts have been made to develop advanced and smart technologies that can predict and prevent asphaltene precipitation. In the history of asphaltene deposition science, two schools of thought have emerged to predict the phase behavior of asphaltene. One school uses colloidal science techniques, believing that asphaltene exists in oil at a colloidal state. The other school adopts thermodynamic methods, believing that the asphaltene occurs in oil in a true liquid state. The main drawdowns of asphaltene deposition in some reservoirs that are prone to asphaltene precipitation are the alteration of reservoir rock's wettability, and the plugging of the formation, flowlines and separation facilities. Different production strategies have been developed to eliminate or reduce the asphaltene precipitation. As asphaltene properties are dependent on its composition, as well as the reservoir temperature and pressure, thermodynamic and kinetic control strategies are utilized to control the pressure and temperature of the system or the conditions of solid formation. Common intervention techniques include stimulating the well periodically using a mixture of acid, xylene, and mutual solvent. Advancement in the asphaltene flocculation-inhibitor treatments allows it to be used in treating the asphaltene in the reservoir without damaging the formation. There are some limitations and environmental restrictions on the current conventional intervention techniques associated with using low flash-point chemicals. These limitations can be resolved by using environmentally friendly techniques, such as laser energy to disturb asphaltene particles. This paper will discuss the asphaltene precipitation and deposition phenomena, preventive and detection techniques, and intervention methods and their limitations, providing a comprehensive overview on the current practice in asphaltene remediation and prevention.
Abstract In the last two decades, the oil industry has dedicated considerable resources and efforts to developing chemical treatments to remove near-wellbore damage. The two main lines of work include formulations with multiple components (either solvent-based or water-based) and multifunctional microemulsion technologies that combine solvent-based and water-based treatments in a single-phase fluid. Microemulsion technology has been applied in onshore and offshore wells, open-hole and cased-hole wells, newly drilled wells, and mature fields with issues of declining production. Various formulations are currently used for near-wellbore remediation in the oil industry. This paper reviews publications relevant to near-wellbore remediation, in particular those that discuss microemulsion treatments. The review covers types of near-wellbore damage (emulsions, drilling fluids damage, sludge, scales, wettability alteration, paraffins and asphaltenes deposits) and the results of microemulsion evaluation and near-wellbore damage treatments. The paper also presents a suite of laboratory tests for microemulsion evaluation and selection for near-wellbore remediation.
Oladunni, Oluwatobiloba (Energia Limited) | Aihevba, Leste (Energia Limited) | Dokubo, Richard (Energia Limited) | Kudayisi, Ayopo (Energia Limited) | Obadaki, Muaz (Energia Limited) | Eze, Celestine (Energia Limited) | Eze, Modestus (Energia Limited) | Ibama, Chika (Energia Limited)
Abstract Well Intervention operations are carried out to improve production performance of a declining well, restore production to a well that quit, or improve well integrity, among other reasons. Well bore clean out and stimulation are two of the common well intervention operations done on producing oil and gas wells to improve performance. Well AA, a major oil and gas producer started to decline after three years of production, therefore a well bore clean out and stimulation exercise was designed to improve performance of the well. The first Intervention operation was planned after various crude sample and precipitate analysis reports showed organic deposits (wax and asphaltenes) in the well. Slickline drift also indicated a restriction in the tubing. The treatment recipe for the well intervention was designed based on laboratory test carried out on the crude and precipitate sample that showed an 85% dissolution of the organic deposits in Xylene and 55% dissolution in Solution Z (a mixture of Xylene and HCL). The 85% dissolution was considered adequate to ensure a complete wellbore clean out, with Solution Z planned as the contingent treatment recipe for any solid deposits not dissolved by Xylene. Contingent on the successful wellbore clean out, a matrix stimulation was to be done using an Acid preflush and Regular clay acid as the main treatment. But this operation failed because instead of resulting in an increase in production, the well couldn't produce to surface and had to be shut-in. This paper will review the problems encountered from the unsuccessful intervention of well AA because of the lack of a detailed recipe design to find the best treatment to dissolve organic deposits in the well and precipitates, as well as residues formed from the reaction between organic solids and inorganic acids. In addition, this paper will present the detailed work that went into designing the right treatment recipe for well AA that resulted in successfully reviving the well after the initial failed intervention operation to become a prolific producer of over 1500 stock tank barrels of oil per day.