The production of heavy and extraheavy oil is difficult because of its rheological properties caused by high asphaltene content. Upgrading these unconventional oils requires large amounts of energy, decreasing the production's cost-effectiveness. Nanoparticulated catalysts have been shown to improve enhanced recovery of these oils by altering their physicochemical properties, including asphaltene content. This paper presents an investigation into the effect of catalytic nanoparticles on the efficiency of recovery from continuous steam injection. Several in-situ techniques have been used to enhance heavy- and extraheavy-oil recovery with the objective of upgrading the oil and improving its viscosity and mobility.
An asphaltene threat was identified in production wells located in a Gulf of Mexico deepwater field. During reservoir-fluids characterization, asphaltenes were identified as a key risk factor for successful field development. This paper presents an integrated approach to evaluate the key elements of asphaltene risk for deepwater projects, the strategy to manage the issues during production implementation, and aspects to be considered in the mitigation of asphaltene in the field-development plan. Asphaltene precipitation and deposition can occur at different stages during petroleum production, causing reservoir formation damage and plugging of pipelines and production equipment. Remediation of asphaltene deposits requires solvent-soaking operations, followed by removal through exposure to turbulent flow.
In a carbonate field under high pressure and high temperature (HP/HT), a gas-injection scheme has been assessed to improve oil recovery through pressure maintenance and miscible displacement. The potential study assumed sequential application of several gas-injection concepts, including raw-gas injection and acid-gas injection (AGI). Flow-simulation studies of these concepts revealed a variety of compositional changes to the in-situ fluid, depending on the injection scheme and composition of the injected gases. Fluid compositional change is a common trigger of asphaltene instability; therefore, to ensure a robust gas-injection development, it is important to evaluate the risk of asphaltene precipitation. Because of high hydrogen sulfide (H2S) concentrations of AGI fluid under HP/HT in-situ reservoir conditions, it is difficult to take an experimental approach for evaluating gas-mixed asphaltene-flow assurance at a normal laboratory.
Flow of paraffinic hydrocarbon liquids within extended pipeline networks or wells, where the environment/bulk temperature is below the cloud point or wax-appearance temperature (WAT), could result in precipitation of wax from the bulk fluid. Precipitated wax crystals from crudes deposits on the inner pipe wall could lead to reduced flow area or even complete blockage and could present a costly problem in the production and transportation of petroleum products. Timely removal of such deposits is extremely important to avoid associated problems. This paper illustrates a numerical approach to estimate the deposition profile and its effect on flow-related parameters. Later, the procedure is validated with field data from a North Sea offshore production facility.
When planning an offshore exploration and production project, operators must consider several potential pitfalls that could derail their progress. Any number of things can turn a hot prospect into a nightmare. One of the things that can be particularly costly is a class of molecular substances that the average person likely encounters on a daily basis. These molecules, the asphaltenes, are used around the world in city streets, sidewalks, parking lots, roof shingles, and buildings. However, there is a reason why asphaltenes are often referred to as the "cholesterol of petroleum" (Kokai and Sayegh 1995).
As offshore exploration and production projects move into deeper waters, the flow assurance issues that operators face have grown larger in scale and more complex, an expert said. In a presentation held by the SPE Flow Assurance Technical Section, "An Insight to Current Flow Assurance Technologies," Phaneendra Kondapi discussed the technologies being used and developed to solve the problems related to flow assurance in offshore projects. Kondapi, chairman of the technical section, is a senior technical adviser at Granherne, a subsidiary of KBR, and a professor of subsea engineering at the University of Houston. Kondapi named five areas of technological developments that address and remedy the problems. The solutions are thermal, chemical, hardware, operating, and software.
The deposition of paraffin with a high molecular weight in crude oil is difficult and often expensive to treat using chemical methods. As owners and operators look to reduce flow assurance costs, the development of inhibitors of paraffin deposition has become a greater priority, an expert said. Speaking at the 2016 Gulf of Mexico Deepwater Technical Symposium in New Orleans, Gee Williams, a manager of business development at Halliburton, discussed a strategy the company used to test the effectiveness of paraffin inhibitors, as well as the results of the company's test on a sample of condensate from the Eagle Ford shale formation. A typical paraffin field test involves three stages: a test for wax solubility, a test for wax deposition, and the analysis of the wax deposits. Williams said cross-polarized microscopy is the best testing method in deep water for wax solubility in crude oil.
Paraffin deposition can be a source of serious fouling and plugging issues in flowlines and other oilfield production equipment. In a presentation hosted by the SPE Flow Assurance Technical Section, Saugata Gon discussed the development of a new test method to screen paraffin chemistries, the Dynamic Paraffin Deposition Cell (DPDC). Gon is a principal chemist in the upstream energy services division at NALCO Champion. Chemical mitigation and remediation for paraffin deposition relies on paraffin inhibitors and dispersants. Today, the most commonly used high throughput paraffin inhibitor screening tool is the cold finger method, where a magnetic stirrer agitates a solution at the bottom of a 100-mL bottle.
The Ultra Flow centralizers from Oilfield Improvements are ideal for full-circle wiping of paraffins in the inner diameter tubing. They are field-installed from a two-piece, snap-together guide made from Amodel, a glass-reinforced PPA resin. The centralizers have higher gripping force on sucker rods and more fluid flow-by volume compared to other commercially available centralizers.
Asphaltenes represent the heaviest fraction of crude oil, which are known to precipitate when the crude is added to aliphatic solvents such as n-pentane or n-heptane and yet remain soluble in light aromatic solvents such as benzene or toluene (Gawrys et al. 2006; Borton et al. 2010). They are characterized by highly complex structures that contain multiple aromatic rings and have a large hetero-atom content (e.g., nitrogen, oxygen, and sulfur) and metal content (e.g., vanadium and nickel) (Yarranton 2000; Hashmi and Firoozabadi 2012). Asphaltenes tend to self-associate on a molecular level, depending on the composition, temperature, and pressure of the system. Precipitation of the particles out of solution results in flocculation, where they begin to deposit on hydrophobic surfaces such as metal pipes and surface equipment used for the production and transportation of crude oils (Khvostichenko and Andersen 2009). These tendencies result in reduced flow or complete blockage of producing wells and surface equipment, including pumps, pipelines, and separators.