The effective stimulation of wells in offshore environments where the removal of existing completions is either not feasible or imparts significant cost implications can pose increased challenges for effective fluid delivery to the desired pay zones. This paper documents the challenges encountered in a sandstone reservoir requiring acidization and presents a hydrofluoric (HF) acid/aminopolycarboxylic acid (APCA) fluid stimulation methodology and ensuing field validation. Frac-pack sand control is the preferred completion method in many wells located offshore West Africa. This method presents the following challenges during the life of the well: Potential for underperforming well productionScreen integrity concerns on production hot spot impact points, resulting in reduced production rates or leading to potential long-term well failureLarge screen length or multizone completions leading to diversion challenges for any potential stimulation fluidRemoval of existing completion not permitted Wells in this area were previously stimulated using complicated fluid trains and sequences with strong HF acidizing systems; however, this stimulation approach encountered complications that included the following: Ineffective stimulation fluid placement, leaving areas under-stimulatedSpacers and pre-flushes necessitating large treatment volumesIneffective stimulation caused by fast reaction ratesFluid compatibility concernsPotential limitation of penetration of live acidPotential for rock disintegration, leading to accelerated sanding in the wellbore The HF/APCA fluid was developed and validated for use in such reservoir types, and the fluid qualification is documented and presented. The fluid pH is low, maximizing the generation of HF acid with an acid-soluble chelant. This chelant technology provides unique sandstone acidizing advantages, especially for mixed mineralogy (carbonate/sandstone) formations, coupled with simultaneous dissolution and/or removal of Ca, Mg, or Fe carbonate scales and fines (clay and silica) accumulated in proppant packs, perforation tunnels, tubing, and downhole tools. The fluid is designed such that historic spacer and pre-flush requirements can be eliminated, resulting in more efficient, effective treatment. The system includes health, safety, and environmental advantages; it is a readily biodegradable, nonhazardous material and is not considered a marine pollutant. In this field, the new chelant-based stimulation fluid used alongside engineered diversionary systems provided the ability to address the demands encountered in these wells. The field validation detailed in this paper documents the successful outcome of the fluid technology. Post-stimulation evaluation showed an improved velocity profile across the screens, indicating successful diversion into the underperforming reservoir sections. This result and the overall skin reduction allowed for a production uplift of 48%.
Using hydrofluoric (HF) acid for the removal of clays and silica minerals impairing permeability in sandstone formations requires fluids free of sodium or potassium ions. High temperatures (> 300°F) further limit HF acid use and its effectiveness because of potentially damaging effects to the formation and its corrosivity. This paper discusses laboratory testing of an aminopolycarboxylic acid (APCA) fluid containing 1 to 1.5% HF acid and highlights its advantages and differentiating characteristics with respect to previous HF acid fluids. Core flow testing at 360°F was conducted on outcrops of two types of sandstone representing a heterogeneous (65% quartz and illite/kaolinite with feldspars) and a clean (95% quartz) type of mineralogy. The APCA fluid containing HF acid, which incorporates a modulating agent for the HF acid-secondary reaction on aluminosilicate minerals, was compared to the pure APCA (pH 2) fluid and formic acid. Effluent analysis of the spent fluid was completed by inductively coupled plasma (ICP) optical emission spectroscopy (OES). Corrosion inhibition testing was completed for coiled tubing (CT) and carbon steel (NT-95) up to 360°F, employing various classes of inhibitors. Using an APCA chelating agent in sandstone HF acidizing expands the temperature range of application and the type of minerals that can be exposed to such fluid. High-temperature HF acidizing is also delimited by the type of steel tubing that can be exposed to such fluid, placing significant demands on corrosion control. Laboratory results obtained in this investigation demonstrate that corrosion can be well managed for a fluid having a pH of 2.5 and HF acid concentrations of 1 to 2% from 250 to 275°F and at 300°F with a pH of 4. Testing results show that the APCA/HF fluid, having a pH of 2.5, can effectively be used to treat heterogeneous sandstone of moderate carbonate content at 360°F and is also compatible with a clean sandstone. The APCA/HF fluid stabilizes the most problematic ions in the spent fluid—Al3+, Fe2+/3+, Ca2+, and alumino-fluorides—without the need for acid preflushes and without maintaining highly acidic conditions. Comparison to formic acid and HF acid-free APCA fluid is presented. Using aminopolycarboxylic acid-type chelants is restricted by the materials commercially available, all of which contain sodium, with one exception, which has ammonium. Hence, HF acidizing has been restricted to ammonium-containing fluids. A differentiating characteristic of the fluid reported here is its ability to sustain Na+ concentrations exceeding 1 M and K+ concentrations in excess of 0.5 M. Furthermore, it is suitable for the treatment of carbonate-laden mineralogy formations up to 360°F.
During effective acid stimulation of mature producing wells, operators often face challenges in terms of achieving sustained production increases. Such challenges in formations subjected to acid stimulation in offshore West Africa include high temperatures (305°F), low reservoir pressure (0.22 psi/ft), highly heterogeneous multilayered formations with large perforated intervals (greater than 1,300 ft net and 2,400 ft gross), and scale in the wellbore, perforations, and sometimes in the near-wellbore area (NWA). Wells in this area, when treated with conventional acid systems based on hydrochloric acid (HCl), only sustain the productivity increase for very short periods. Such conventional acid systems have been based on 7.5% HCl and 10% acetic acid (AcOH) with high loadings of corrosion inhibitor, iron sequestering agents, demulsifiers, and antisludge agents. This approach has constraints that can potentially include the following: Ineffective stimulation attributed to fast acid reaction rates Limited penetration of live acid Rock disintegration Damage from reprecipitation of acid reaction products, such as iron and mineral fines from wellbore scale Damage from high corrosion inhibitor loading Fluids (stimulation and reservoir) incompatibility The use of a newly developed aminopolycarboxylic acid (APCA) based stimulation fluid provides advantages that circumvent these constraints. The introduced technology delivers a stimulation system that provides deeper stimulation treatments because of lower reaction rates and potentially a more effective wormhole type of reaction for the reservoirs' characteristics. This stimulation fluid also chelates reaction products to help enable superior cleanup of the acid system. This system also requires lower loadings of corrosion inhibitors, demulsifiers, and antisludge agents, and is more compatible with formation lithology, lowering the risk of formation damage.
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