|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Abstract The success of conventional matrix acidizing treatments with hydrochloric acid is often limited due to rapid acid spending at low injection rates. Previous studies have demonstrated the effectiveness of ethylenediaminetetraacetic acid (EDTA) as an alternative to HCl for stimulating carbonate formations. This work extends the study to include other chelating agents of the aminopolycarboxylic acid group. Results show that 1,2-cyclohexanediaminetetraacetic acid (CDTA) and diethylenetriaminepentaacetic acid (DTPA) effectively wormhole in limestone, even when injected at moderate pH values and at low flow rates where only face dissolution would occur with HCl. Rotating disk experiments have demonstrated that the dissolution of calcite by chelating agents is not necessarily limited by reactants transport to the surface. Therefore, we have derived a modified Damkohler number that includes the effects of reactant transport, reversible surface reactions, and products transport. The wormhole structure and permeability response depend on this modified Damkohler. In addition, there exists an optimum modified Damkohler number at which a single dominant wormhole channel is obtained and the pore volumes to breakthrough is minimized. This optimum Damkohler number occurs at approximately 0.17 for all of the fluids investigated. Introduction Matrix acidizing treatments often require low injection rates to prevent fracturing the formation rock or are required in heterogeneous formations with zones of low-conductivity (which need stimulation the most) that accept acid at low rates. It is at these low injection rates that the problem of rapid acid spending severely limits the acid penetration distance. The injection of hydrochloric acid into carbonate formations at low rates results in face dissolution, or complete dissolution of the carbonate matrix near the wellbore. This face dissolution consumes large volumes of acid and provides negligible increases in the conductivity of the formation. Various acid systems such as oil external microemulsions containing HCl and foamed acids (nitrogen gas and aqueous HCl) have been shown to stimulate carbonate formations at lower injection rates. However, strong acids such as HCl destabilize asphaltene particles in crude oil and cause the formation of asphaltic sludge and rigid film emulsions. This common problem is even more severe when ferric ions are present. A variety of acid additives (anti-sludging agents, corrosion inhibitors, and iron reducing agents) have been used to prevent the sludging problem. However, their effectiveness is limited by the need to obtain a compatible combination of additives and a lack of understanding of the complex chemistries involved in the precipitation reactions. These limitations demonstrate the need for alternative stimulation fluids that combine the ability to stimulate at low injection rates with fluid properties that are not conducive to asphaltic sludge precipitation or corrosion problems. Previous work in our laboratories has demonstrated that the chelating agent ethylenediaminetetraacetic acid (EDTA) can effectively wormhole in limestone, even when injected at moderate or non-acidic pH values (4 to 13) and at low flow rates where HCl is ineffective. The dissolution mechanism involves chelation of calcium ions and does not require conventional acid attack. This ability to stimulate under non-acidic conditions combined with the ability to chelate metal ions provide other benefits of using EDTA. It has been shown that EDTA does not induce the precipitation of asphaltic sludge from crude oil, even in the presence of 3000 ppm of ferric iron. In addition, corrosion is negligible for alkaline solutions of EDTA below 204 C (with possible exceptions when copper, tin, and aluminum are present). Therefore, EDTA provides the properties necessary for a matrix stimulation fluid (wormholes formed in carbonates at low injection rates) while not requiring additives to control corrosion or asphaltic sludge precipitation. The success of EDTA as an alternative stimulation fluid for carbonate formations has led to further investigation of chelating agents of the aminopolycarboxylic acid family. P. 23
Schulze, Kai (RWE DEA A.G.) | Kersten, Christoph | Verient, Gery (RWE Dea AG) | Oswald, Wolfgang (RWE DEA A.G.) | Dammerer-Kerbl, Michael (RWE DEA A.G.) | Empl, Christoph (RWE DEA A.G.) | Marchel, Christian (RWE DEA A.G.) | Karsch, Harold (RWE DEA A.G.)
Abstract The Rotliegend sandstone reservoir of Voelkersen (Northwest Germany) is a low permeability (kabs 2–4 mD), high pressure high temperature gas field (650 bar, 160°C). Its formation water is of high salinity (250 g/l) and characterised by its very high calcium content (= 40 g/l). The reservoir section of a partly depleted acceleration well was drilled using saturated water based sodium/potassium formate brine. For corrosion protection the pH value of the brine was adjusted to pH 10.5 using a bicarbonate/carbonate buffer. After gas production of 70 million m3(Vn) the production collapsed as a result of an unexpected build-up of calcium carbonate scale in the well bore area and the tubing. Two mechanisms have been identified as the cause of this scale formation. First the interaction of the caustic filtrate of the formate brine with the calcium rich formation water leading to a direct calcium carbonate precipitation. Second the enrichment of the formation water with bicarbonate by interaction with the caustic mud filtrate. This has resulted in calcium carbonate precipitation caused by the rise of the pH value of the water. The latter is resulting from decarbonisation caused by the pressure relief in the well bore area as a result of production. After subsequent mechanical and chemical scale removal, the gas production was even higher than at the initial state of production. However, having additionally produced 90 million m3(Vn) the production dropped again. This breakdown is attributable to an increase of bicarbonate in the formation water by a slow process of decomposition of formate left in the formation. This has resulted in subsequent scale formation following the decarbonisation process described above. To minimise the scaling potential of the formate brine while maintaining sufficient corrosion protection, careful adjustment of the pH value of the formate brine while drilling the reservoir section was implemented for successive wells. For already damaged wells several potential treatments have been identified and introduced, such as scale inhibition treatment integrated in hydraulic fracturing. Introduction The field Voelkersen, a Rotliegend sandstone natural gas reservoir in Northwest Germany between the cities of Bremen and Hanover, is a high pressure high temperature (HPHT) natural gas field (650 bar, 160°C). The first well in this field started production in September 1994. Recently a new acceleration well was drilled using formate brine with a low solid content to minimise differential sticking especially when partly depleted zones had to be drilled with a drill-in fluid that had to be overbalanced at the initial reservoir pressure of about 650 bar. This resulted in drilling the partly depleted reservoir target zones with an overbalance of about 250 bar. This high overbalance is due to the existence of rather small gas bearing layers in the last drilling section which are under initial reservoir pressure. A further reason for using formate brine was the high deviation of the borehole trajectory implying the risk of solid sacking. In this paper the reasons of the production breakdown caused by scale formation resulting from the interaction of the formate brine and the calcium rich formation water will be highlighted. Possible ways of treatment will be discussed as well as the adjustment of the formate brine to prevent such formation damages in future.
A potential mechanism for part of the production decline observed in the Prudhoe Bay field is siderite (iron carbonate) scale deposition. This laboratory investigation focused on evaluating the effect of the existing downhole scale inhibitor program on the proposed siderite formation damage mechanism. A tube block test was employed to generate iron carbonate and evaluate commercial products for its inhibition. This study indicates that the current inhibition program for barium sulfate and calcium carbonate is not protecting against damage by iron carbonate deposition. The other products tested were also ineffective. Furthermore, precipitation of the scale inhibitors by iron(II) is suspected. There is no field evidence of damage from this precipitation with the current inhibition program.
The deposition of inorganic scales is a common operational problem. Scale inhibitors are effective at preventing scale deposition at concentrations significantly below the levels required to sequester or chelate the divalent cations. The molar ratio of precipitate kept in solution to the inhibitor used is typically of the order of 10,000:11. Scale inhibitors prevent, slow, or distort crystal growth by blocking growth sites2. They are a viable solution for many types of scale due to the low cost of protection.
Iron (II) carbonate is not a common scale problem and its inhibition hasn ot been studied to any extent. Thin layers of iron carbonate are frequently observed on tubulars recently pulled from service; this is usually attributed to corrosion and causes no operational problems. Under certain conditions iron carbonate deposition serves to passivate metal surfaces against further corrosion. However, in formations with a high iron carbonate mineralogy, it is possible for significant deposits of siderite to precipitate from the produced water.
Iron (II) is a common component of formation waters, and produced waters commonly contain a few mg/L of iron3. However, in rare instances the natural iron (II) content may reach 100 mg/L. Iron (II) is a stable species in anaerobic environments, however; when exposed to air iron (II) quickly oxidizes to iron (III)4. Iron (III) forms insoluble oxides and hydroxides which precipiate from solution.
Because of the rare occurrence of iron carbonate scale due to precipitation from production water and because of the need for anaerobic experimental procedures, inhibitory products specific for iron carbonate scale have not been developed. The existing products, developed for calcium/barium, carbonate/sulfate scales have not been evaluated for iron carbonate inhibition. In this laboratory study a method was developed for generating iron carbonate in a tube block testing device and several products were evaluated for iron carbonate inhibition.
Abstract Gas hydrate formation during deep-water offshore drilling is a well-recognized operational hazard. Plugging the BOP stack, choke and kill lines with hydrates can cause a serious well control problem. We conducted an up-to-date review of the drilling practices and mud formulations applied in deep water drilling as related to gas hydrates control and mitigation. The review indicated that Salt/polymer mud systems are the most commonly used mud formulations in the Gulf of Mexico, North Sea and offshore Brazil. Drilling with these systems has been successfully achieved to water depths of up to 7500 ft (2287 m). In the second part of this work, we measured the hydrate phase equilibrium of 25 drilling fluid formulations. The testing also included two new spotting fluids formulations. The testing results indicated that, on weight basis, NaCl is the best thermodynamic inhibitor among the salts tested in this work, which are NaBr, Na-Formate, KCl, and CaCl2. Although the high solubility of the Na-Formate makes it possible to increase the hydrate suppression beyond that of NaCl, the former is less effective on weight basis than NaCl. The glycols are considerably less effective inhibitors, on weight basis, than the salts. However, greater degree of suppression can be achieved by using mixtures of salts and glycols. Among the tested glycols, ethylene glycol showed the best performance compared to AQUA-COLTMS, GEOMEGTM D207, and HF-100NTM. Introduction Gas hydrate formation during deep-water offshore drilling and production is a well recognized operational hazard. In water depths greater than 1000 ft (300 m), the sea bed conditions of pressure and temperature become conducive to gas hydrate formation. In a well control situation, although the kick fluid leaves the formation at a high temperature, with an extended shut-in period it can cool to seabed temperature. With high enough hydrostatic pressure at the mudline, hydrates could form in the BOP stack, choke and kill lines, as have been observed in field operations Record water depths are continuously being set by operators in search of promising reserves in deep waters. The first deep water well to be drilled in Norwegian deep water licenses will start in summer 1997. The extremely low mud line temperature of 28.4 to 30.2 F (−2.0 to −1.0 C) in this area brings the challenge of designing suitable drilling fluids that both prevent hydrate formation and meet other drilling requirements. The current practice in deepwater drilling is to suppress the hydrate formation temperature by using highly saline drilling fluids formulated from NaCl or other salts. This solution is applicable for the Gulf of Mexico, but insufficient for the conditions to be encountered in the Norwegian deep waters. At extreme water depths or extremely low mudline temperatures, this thermodynamic inhibition alone may not be sufficient to prevent hydrate formation. Instead, the use of kinetic inhibitors or crystal modifiers, in conjunction with thermodynamic inhibitors, may pave the way for successful operations in such an environment. The definition of kinetic inhibitors (to distinguish them from the classical thermodynamic inhibitors such as polar compounds and electrolytes) comes from the effect of the chemicals on the nucleation and growth of natural gas hydrates, both of which are time dependent and stochastic processes. The Impact of Drilling Fluid Ingredients and Additives on Hydrate Formation In a study of hydrate formation in drilling fluids, Guar et al. reported that salt and bentonite have the most significant impact on the hydrate phase equilibrium relative to any other mud component. This conclusion was based on a statistical analysis of 17 test runs performed at pressures below 1280 psia (8.83 MPa). The tested fluids contained variable amounts of bentonite, thinner, caustic, barite, salt, xanthan gum, partially hydrolyzed polyacrylamide (PHPA), oil, drill solids, and methanol. P. 35^