Calcium carbonate scale impacts oil production in a large number of fields worldwide. This scale is generally managed by acid washing to removal the scale and/or by performing scale inhibition treatments. The choice between inhibition and regular stimulation is cost driven, with high cost operations generally selecting inhibition. However, even in wells where inhibition is planned, some scale can be deposited either prior to scale inhibitor deployment, or after the end of the scale inhibition treatment life. Consequently, stimulation treatments are required in many wells, in order to remove calcium carbonate scale. Combining scale inhibition with scale removal treatments offers several advantages. Firstly, in many operating areas, it would reduce the well intervention cost by making the operation a single intervention, offering significant economic benefits and a reduction in well intervention risk. Secondly, pumping a combined treatment not only reduces the risk of scale re-precipitation during the stimulation treatment, but it ensures that the zones that are stimulated are also inhibited. This directly protects value added by the scale removal treatment. This paper details the development of combined scale removal and inhibition treatments, from project initiation to readiness for field trials. The main challenges that need to be addressed in order to achieve an effective combined treatment are discussed. Data from a laboratory study, investigating the potential for combining scale inhibitors in hydrochloric acid, organic acid and scale dissolver systems are presented and the most effective combined systems are identified. Introduction Scale precipitation is a common cause of impaired well productivity, with calcium carbonate being the most common scale that is formed. Hydrochloric acid is frequently used for removal of carbonate scale,1–3 as it generally offers both the best performance and the lowest cost. Such acid treatments can be very effective in providing short term stimulation benefits to such wells, but the treatments are often short lived.3 For high temperature applications, organic acids have been used in preference to hydrochloric acid, due to corrosion concerns.4–5 The dissolution of calcium carbonate by chelating agents is also well known6–10. Treatments with chelating agents to remove calcium carbonate scale have been performed,6 but dissolution rates are generally lower than with acid and treatment economics tend to restrict their use. Calcium carbonate scale deposition can be effectively inhibited in most fields, with scale inhibitor squeeze treatments being widely used to prevent scale build-up11–13. In these squeeze treatments scale inhibitor is retained in the formation either via adsorption onto the rock surface14–16, or by precipitation (or phase separation) of the calcium salt of the inhibitor. Precipitation squeezes offer increased squeeze life17, but may have an associated risk of formation damage during treatment,18 especially in damage sensitive formations. Although scaling potential can be predicted19–21 and proactively treated, it is still common for scale to form in some wells, either before an inhibition treatment is pumped or after the end of the treatment life. This can occur if there is insufficient early warning of the onset of scale, or if limitations in well access or equipment availability delay a planned treatment. Consequently, even when inhibition is the scale management strategy, the need still arises for scale removal treatments. Conversely, when acid stimulation is the preferred scale management tool, there would be a benefit in reducing treatment frequency if the job life could be extended by simply adding an effective scale inhibitor to the acid system. Although the potential benefits of such combined treatments have been recognised, it has been reported that the post-acid treatment environment prevents scale inhibitors from performing effectively.22 The current approach to this problem, therefore, is to pump sequential scale removal and scale inhibition treatments.

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The Caballos formation is thick laminated sandstone with less than 10% of total clays and permeability ranging from 20 mD to as high as one Darcy. However, the production from this formation is often limited due to the low critical flow rate in the matrix (less than 1 mL/min) and associated fines migration as shown in several tests. Historically matrix acidizing and hydraulic fracturing treatments in this formation have only been partially successful due to destabilization of the clays and inadequate fines stabilization, along with the incompatibility of the crude oil with many conventional acid systems. In order to overcome the limitations associated with the use of conventional acid systems an extensive laboratory study was conducted using a non-acid based stimulation fluid. The base fluid selected was a newly developed chelating agent that is very tolerant to high concentrations of both carbonate and aluminosilicates, and iron and zeolite bearing minerals. By including acid salts in the fluid it proved possible to develop a fluid system with the equivalent dissolving power of a conventional 6:1.5 (HCl: HF) mud acid, even at temperatures as low as 180°F. Testing also showed that the fluid was capable of controlling fines migration and that a scale inhibitor could be included in the formulation, while the fluid system exhibited excellent compatibility with the formation fluids throughout the field. The newly developed non-acid fluid system provides some unique advantages for matrix acidizing applications and in particular for stimulating the Caballos formation 1) Minimizes the risk of secondary and tertiary precipitation due to the nature of the chelating agent 2) A single treating fluid instead of the multiple fluids/stages used in a conventional treatment 3) Greatly reduced sludging and emulsion tendencies compared to conventional acid systems (without the addition of surfactants or demulsifiers) and much lower corrosion rates 4) The ability to stabilize fines present in the matrix 5) Allows for a scale inhibitor to be included in the treating fluid 6) Reduces the logistics and HSE risks during the execution of the treatment. This paper reviews the laboratory testing including an extensive core flow testing performed to develop a new nonacid treating fluid for both matrix acidizing and dual stimulation applications in the Caballos formation and its implementation in the field, illustrated with case studies and production data. Introduction In the Orito field in the south of Colombia the most prolific reservoir is the Caballos Formation, 250-ft thick interbedded fluvial/deltaic and marginal marine sands that originally contained more than 700 million bbl of oil in place. Due to distinct changes in the vertical lithology the reservoir is divided into four distinct flow units or layers A, B, C and D in ascending order shown in Fig 1. Furthermore, the production of the wells along with a petrographic and petrophysical study has shown that there are two distinct zones of markedly different reservoir quality. The lower zone - layer A, is a much better quality reservoir than the upper zone. Layer A is a well sorted sand with kaolinite present in the pore spaces. The porosity and klinkenberg permeability varies from 12 to 14 % and from 100 to 300 mD, respectively. While, the upper zone - layers B, C and D - is a much poorer quality reservoir. A single facies of poorly sorted and loosely packed quartz with kaolinite in the inter-granular spaces. The porosity in this upper zone is predominantly intergranular ranging from 11 to 12 % and the klinkenberg permeability from 5 to 150 mD, (Fig. 2). In addition, due to the presence of a number of major and minor faults the reservoir is compartmentalized. The complexity of the stratigraphy reflected in the marked changes in the quality of the reservoir and the properties of the oil in place, across the field. Due to the fractional composition of the oil, the properties of the crude oil also vary between the different layers, independently of the location of the wells on the structure.