Organic Formation Damage Control and Remediation

Abstract

Organic skin damage in oil producing wells is a major factor in the loss of productivity and revenue. Paraffin and asphaltene deposition in the formation and around the well bore creates a barrier for the transportation of the crude oil to the tubing. Many producing wells have experienced a production decline that can not be explained by reservoir depletion. Organic damage may occur naturally or through various intervention practices used in the oilfield. An increased awareness of the potential for ongoing organic damage has been developing slowly over time. Better methods of problem identification and programs to remediate these problems have been developed in recent years. The potential sources of organic damage, problem identification test techniques, chemical selection and application methods are discussed. Numerous case histories for a variety of problems are also presented. Introduction Two naturally occurring components of crude oil are paraffins and asphaltenes. Paraffins are composed of carbon and hydrogen atoms with a carbonchain length starting at C18–20 up to C70 or higher. Though paraffins are usually straight-chained hydrocarbons, they can also contain a variety of branched alkyl or cyclic groups. Asphaltenes are heterocyclic unsaturated macromolecules consisting primarily of carbon, hydrogen, and minor components such as sulfur, oxygen, nitrogen and various heavy metals. These higher molecular weight components of crude oil are inequilibrium at "normal" reservoir condition. As crude oil is produced thisequilibrium is upset by a number of factors such as the following: temperature declines, pressure reductions, addition of miscible gases and liquids, acidizing, hot oiling and other oilfield operations. The primary mechanism for paraffin deposition is thermal cooling. Decreases in temperature promote paraffin deposition. The key mechanisms for asphaltene deposition are the decrease in pressure and the introduction of incompatible fluids.1,2,3 Problem Identification In order to remediate the damage it is first necessary to identify thesource of the problem. The first step in this process is a thorough systems analysis. Critical information necessary at this stage consists of the following: production history, current production rates of oil, gas and water, drive type, well depth, temperature and pressure profile, well configuration, fluid level, EOR technique, stimulation and maintenance history. The second step in the process is laboratory testing on samples of crude oil, water and solid deposits. The crude oil is characterized by wet chemical and instrumental analysis for % paraffin, % asphaltenes, % asphaltic resins, %aromatic and % saturates. A cloud point, pour point, gas chromatograph andviscosity profiles are also run. A series of specialized deposition/instability tests are run to investigate the potential for deposition. For paraffinic crudes these consist of paraffin deposition tests using cold fingers or other thermal deposition devices. The potential for asphaltene deposition is studied by conducting depressurization studies on live oils to determine the asphaltene flocculation point. For surface samples of crude oil a variety of asphaltenein stability tests are conducted. These consist of flocculation point determinations using a variety of anti-solvent titration and measurement techniques. Solid samples are analyzed using similar wet and instrumental techniques. Water samples are analyzed for elemental composition and scaling tendencies are determined. From the information gathered using these various tests, the source and magnitude of the problem can be identified. Primary, secondary and even tertiary problem sources can be identified as drivers for formation damage.

Measuring asphaltenes and resins, and dipole moment in petroleum fluids

“…heptane . Although acids and heavy paraffins may coprecipi-Ž tate with asphaltenes Becker, 2000;Newberry and Barker, . 2000 , precipitation with n-alkanes is the main separation method of asphaltenes from petroleum fluids.…”

CO2 mobility control and sweep efficiency improvement using starch gel or ethylenediamine in ultra-low permeability oil layers with different types of heterogeneity

“…The content of saturated hydrocarbon is 47.14%; the content of aromatic hydrocarbon is 27.52%; the content of resin is 21.87% and the content of asphaltene is 3.47%. Newberry and Baker (2000) built SARA equation as follows to calculate colloid unstable index:…”

Enhanced Oil Recovery (EOR) by Miscible CO2 and Water Flooding of Asphaltenic and Non-Asphaltenic Oils

“…Danesh et al [31] observed that asphaltene precipitation increased as the pressure drop increased in a Visual micro model. Newberry and Barker [32] also reported that the key causes of asphaltene precipitation are pressure decrease and the introduction of incompatible fluids. On the contrary, the asphaltene precipitation of two reservoir oil samples collected from Jilin oil field has been studied under pressure and with/without CO 2 -injection conditions [33].…”