Chemical Stimulation at a Heavy-Oil Field: Key Considerations, Work Flow, and Results
This paper presents the planning and execution of a matrix-stimulation pilot project in the heavy-oil Chichimene Field in Colombia.
Because of current oil and gas industry economics, evaluating the return on investment for any well-intervention campaign is crucial, as is applying an assurance process to help quantify desired production improvement. This paper presents the planning and execution of a matrix-stimulation pilot project in the heavy-oil Chichimene Field in Colombia. The approach is based primarily on a work flow that includes characterizing formation damage, reviewing laboratory tests, validating well selection, and determining economically viable placement and diversion techniques.
Heavy-oil reservoirs are prone to almost every formation-damage mechanism known. Damage mechanisms encountered include fines migration, paraffin and asphaltene deposition, various forms of scale, and clay swelling. Many of these damage mechanisms are compounded by the methods used to produce heavy oil, including slotted liners, screens, and gravel packs, which can plug off as a result of any of the damage mechanisms and, over time, further reduce inflow and well performance.
A process to identify and characterize formation damage in the Chichimene Field was established. For this purpose, several wells were selected to analyze formation-damage distribution. Reservoir-property data were uploaded into a simulator with a dynamic model to quantify the effects of formation damage attributed to pressure drop in the reservoir. The following damage mechanisms were observed.
Drilling- and Workover-Induced Damage. Water, solids, or both, when used in drilling or during workovers, tend to decrease the effective permeability of the formation. Water from drilling fluids contains additives that produce chemical reactions with the formation, which can generate precipitates that plug pore throats. Solids from the drilling and completion fluids also can physically plug or bridge pore throats
Organic Deposition. Organic deposition usually occurs in two forms—paraffin and asphaltenes. Those hydrocarbons classified as paraffins are generally inert. They are resistant to dissolving in acids, bases, and oxidizing agents. Additionally, paraffin deposits often include other materials, such as scale, sand particles, or asphaltenes. Asphaltene deposition is a more subtle form of deposition. It is not usually visible in the field, and extensive laboratory testing is necessary for its detection.
Inorganic Deposition. Common forms of inorganic deposition include calcium carbonate scale and gypsum scale. Less common, but more difficult to treat, are iron-rich deposits and silica scale. Numerous methods exist for the removal of inorganic scale, including simple mechanical methods, such as jet washes and complex acid/solvent washes.
Emulsions. Emulsions occur when two immiscible liquids are energized—in this case, oil and water. In general, emulsions can be treated using various solvents.
Wettability Alterations. Most drilling fluids contain a variety of chemical additives, such as surfactants, to help improve mud performance and characteristics. In some cases, these additives exhibit a high propensity for physical adsorption on the walls of the pore throats. This adsorbed layer reduces the effective pore throat, leading to undesirable phenomena such as permeability reduction and wettability alterations.
Placement Method. Because of long treatment intervals and large permeability variations in this field, using coiled tubing with a fluidic oscillator (FO) was most effective in enhancing fluid placement. The FO causes alternate bursts of fluids within the wellbore. The resulting pressure pulses propagate radially into the formation, carrying the stimulation fluid deeper into the reservoir.
Fig. 1 above shows a typical FO. This tool does not have moving parts and features a metal-to-metal seal, which helps improve reliability, function, and performance.
Treatment Fluids. With the help of a simulator, grid analysis was performed using a distance of 5 ft from the wellbore. This distance was used to help monitor the progress of the various damage mechanisms and define the optimal penetration radius necessary for stimulation treatments. A stimulation trend was created for a solvent and acid treatment designed for 2- and 3-ft penetrations, respectively.
Solvent Treatment. A low-interfacial-tension (IFT) aromatic/aliphatic solvent mixture was used, and a soaking period of 12 hours was allowed for dissolving asphaltenes and paraffins. Low-IFT fluids also promote rapid cleanup of dissolution products during flowback. Formation mobility modifiers (FMMs) were used during treatment. FMMs are blends of solvents, wetting agents, and nonemulsifiers selected and optimized for specific formation types through laboratory interfacial chemical testing. FMMs work by allowing nanosized fluid droplets to penetrate into the formation to help improve fluid recovery and liquid-hydrocarbon production.
Organic-Acid Treatment. A mixture of organic acids (acetic and formic) was used as the main treatment to dissolve carbonates placed into the formation by mud invasion during drilling operations. This treatment prevents clay decomposition associated with hydrochloric-acid-based fluids.
Compatibility Tests. Emulsion and detergency tests were performed for every well to verify that a stable emulsion was not formed between the formation fluids and proposed treatments.
IFT Measurements. A tensiometer was used to measure IFT between the formation fluids and stimulation treatments used. FMMs were used in the solvent treatment to generate lower fluid-surface-tension properties.
The first case study was performed in Well CH-206. The main formation-damage mechanism identified in this well was associated with drilling-induced damage attributed to calcium carbonate used in the drilling mud. Organic deposition was also identified as a formation-damage mechanism.
Before chemical stimulation was performed, circulation was conducted by pumping approximately 1,200 bbl of hot formation water through the annulus.
Coiled tubing was run into the well, reaching a depth of 9,100 ft without encountering restrictions. Upon reaching the bottom, potassium chloride (KCl) brine (2%) was injected (not circulated) at a rate between 0.5 and 1.0 bbl/min. Then, the coiled tubing was positioned at a depth of 8,958 ft and, with closed returns, an injectivity test was performed at flow rates of 0.5, 0.8, 1.0, and 1.2 bbl/min with surface pressures of 67, 546, 650, and 700 psi, respectively.
After the injectivity test, the well was circulated with 55 bbl of formation water to establish injectivity before the first stage of the stimulation was performed. With returns closed, the solvent treatment was pumped and injected into the formation.
After the necessary soaking time, an organic-acid treatment was pumped in three stages using foamed 2% KCl brine as a diverting system. The acid was injected at an average rate of 1.0 bbl/min, and the diverting stages were injected at 0.7 bbl/min and 500 scf/min of 69%-quality nitrogen. A total of 28 bbl of 2% KCl brine was used to displace the coiled-tubing capacity.
Oil-production results from the first five pilot wells are presented in Fig. 2. Oil-production increases were noted in all cases. To date, more than 10 stimulation treatments have been performed successfully using this process.
- The synergy between the stimulation design and a proper placement method yielded productivity increases in this heavy-oil reservoir and improved the level of sustainability under current field production. To date, more than 10 wells have been treated in the same manner with good results.
- The FO tool helped increase the stimulation effectiveness by allowing more-efficient placement of stimulation fluids in near-wellbore regions.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 184974, “Chemical-Stimulation Pilot at a Heavy-Oil Field: Key Considerations, Work Flow, and Results,” by Mauricio Gutierrez, Fernando Bonilla, Layonel Gil, and Wilmer Parra, Ecopetrol, and Pablo Campo, SPE, Alex Orozco, and Monica Garcia, Halliburton, prepared for the 2017 SPE Canada Heavy Oil Technical Conference, Calgary, 15–16 February. The paper has not been peer reviewed.