Part A: Chemical and Physical Properties
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Formate brines are aqueous solutions of the alkali metal salts of formic acid. These salts are readily soluble in water, yielding high-density monovalent brines with low crystallization temperatures. The basic chemical properties of sodium, potassium, and cesium formate brines and their blends are described. This includes properties such as molecular formula, molecular weight, solubility, solution density, anti-oxidant properties, and water-structuring properties.
Formate salts are very soluble in water and they form brines with high density. Mixing tables for sodium, potassium, and cesium formate single-salt brines and powders are presented, together with blending tables for cesium and potassium formate brines. PVT data for the full density ranges of single-salt potassium formate brines and cesium/potassium formate brine blends are tabulated. These tables contain density, compressibility and thermal expansion coefficient as a function of temperature and pressure.
Formate brines are aqueous solutions containing large amounts of dissolved salt and very little water. Their water activities are therefore very low and properties can deviate widely from those of other aqueous solutions. Water activity data for sodium, potassium, and cesium formate single-salt brines and their blends are presented. Colligative properties such as boiling point and vapor pressure are also presented.
Formate brines have relatively low brine viscosities compared to other oilfield brines. For example a concentrated cesium formate brine has viscosity as low as 5 centipoise (cP). Viscosities for sodium, potassium, and cesium formate single-salt brines and blends are presented as function of brine density and temperature.
Crystallization temperature (TCT) is an important property of well construction and intervention fluids that are used in cold weather conditions and/ or under high pressure. Formate brines behave very differently from other oilfield brines (such as halide brines) as they exhibit an enormous supercooling effect and metastable crystals can form in potassium formate brines. This makes it very difficult to measure formate TCTs using standard laboratory methods. We have developed a special method for measuring TCT, which is described in this chapter. In addition, measured TCT data for sodium, potassium, and cesium formate single-salt brines and cesium/potassium formate brine blends are presented.
Formate brines are very unique compared to other heavy oilfield brines, such as halide brines, in that they are compatible with the carbonate/bicarboante pH buffer. Calcium bromide, calcium chloride, and zinc bromide brines cannot be buffered as the divalent cations form a carbonate scale when contacted by the buffer. The natural pH buffering capabilities of formate brines are explained and the benefits of the carbonate/bicarbonate buffer addition are demonstrated by showing pH response of these buffered formate brines to acid gas influx. Methods are described for how to measure pH and determine buffer concentration and buffer capacity in formate brines.
For drilling fluid applications, high thermal conductivity and high specific heat capacity are favorable as they contribute to lower bottom-hole circulating temperatures, which prevents exposure of logging/MWD tools to high temperatures, protects polymers from thermal degradation, and allows quicker temperature equalization when the well is left static, resulting in much faster well stabilization. This means that flow checks can be completed in a shorter period. Water-based fluids, such as formate brines, have a relatively high thermal conductivity and specific heat capacity, which is very favorable compared to oil-based mud (OBM). Measured thermophysical data for a series of sodium, potassium and cesium formate brine blends are presented as a function of temperature.
High-concentration formate brines are very lubricious. Exactly how lubricious these brines are depends on formate concentration. Concentrated cesium and potassium formate single-salt brines and their blends are shown to be even more lubricious than OBMs. The outcome of two large studies on formate brine lubricity is presented.
A fluid’s petrophysical properties are important for the quality of the logs. Logging in formates has traditionally been considered difficult as they have very different petrophysical properties than most other fluids. However, most service companies have now developed formate specific algorithms to interpret formate logs, and they have found many benefits from some of the unusual properties. High-density oil-based muds (OBMs) have very high resistivity (high oil-to-water ratio), which means that good resistivity logs cannot be obtained in these fluids. High-density formate brines are very conductive, and are therefore compatible with the resistivity logging tools. A variety of measured petrophysical properties is presented. Measured resisitivity data are given for single-salt sodium, potassium and cesium formate brines and blends. The dependence of resisitivity on temperature is shown for a cesium/potassium formate brine blend. Some nuclear properties and sonic-velocity data are also included.
Concentrated formate brines are hygroscopic and therefore absorb water from the atmosphere when left in an open container over time. At higher temperatures, however, the evaporation process is more significant and water is desorbed from the brine. A series of measured absorption and desorption data is presented.
Several radioactive cesium isotopes exist from nuclear reactions. Radioactive cesium isotopes are not used for production of cesium formate brine. All of Cabot’s cesium-based salts and brines originate from naturally occurring pollucite ore, which exclusively contains the stable 133Cs isotope. Results from gamma spectroscopy testing of several cesium and potassium formate brine samples are presented along with gamma activities and total alpha/beta/gamma activity for a cesium formate brine.
Formate brines are very unique as they have biocidal properties at working concentrations at the same time as they are readily biodegradable when diluted to low concentrations. They can therefore be discharged safely to the environment. Their natural biocidal properties at working concentrations means that neither the brines nor the organic additives used in the brines will biodegrade during field application or storage. The exact conditions that make formates biodegradable and the cut-off point where bacterial growth is inhibited have been measured and are presented.
Formate brines have been exposed to high temperature conditions in over 300 high pressure high temperature (HPHT) well applications since 1996. During this time they have been exposed for lengthy periods to well temperatures as high as 225°C/437°F without any substantial change in composition or properties. The chemistry of formate decomposition at high temperature is reviewed. It is explained why formate brine exposed to hydrothermal conditions in a deep high-pressure well is able to establish equilibrium with bicarbonate, whilst formate brine exposed to the same temperature in a low-pressure laboratory autoclave with gaseous headspace is not. These explanations are supported by testing conducted by scientists at the Woods Hole Oceanographic Institution.
Part B: Compatibilities and Interactions
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Gas influx is a main cause of corrosion failures in completion and packer fluids. The most destructive gases are carbon dioxide and hydrogen sulfide, which can leak into the wellbore along with other reservoir gases, and oxygen that enters the fluid during circulation at the surface, or in the case of packer fluids, during annular pressure bleed-off operations. The carbonate/bicarbonate pH buffer that is added to the formate brine protects the brine from the acid gas. The detailed chemistry of the events that occur when acid gases enter into buffered formate brines is presented. Protection against damage caused by oxygen is also discussed.
Low solubility of reservoir gases in well construction fluids is important for well control purposes. Changes in volume and density as a consequence of gas influx can have severe consequences. Solubility of typical reservoir gases in formate brines is very low and significantly lower than in water and oil-based muds. This section presents measured solubility data for methane and carbon dioxide in blended cesium/potassium formate brine as a function of temperature and pressure.
Diffusion of reservoir fluids into the wellbore is a serious well control problem with oil-based drilling fluids. In water-based fluids, diffusion of reservoir gases is much lower. The outcome of a study on how reservoir gases diffuse through formate brines is presented.
This section of the manual presents a thorough compatibility review between formate brines and several fluids commonly available on the rig. The fluids that have been tested are halide brines, such as sodium chloride, potassium chloride, sodium bromide, calcium chloride, and calcium bromide. Compatibility with other fluids such as oil-based drilling fluid, synthetic-based drilling fluids, base oil, seawater, well treatment fluids, glycols, and methanol has also been investigated.
One of the most important properties of formate brines is their ability to stabilize biopolymers to high temperatures. Xanthan gum for example can be kept at up to 200°C/400°F in a concentrated potassium formate brine. This is very unique as high density halide brines (calcium chloride, calcium bromide, and zinc bromide) are not compatible with biopolymers due to cross-linking. A thorough review of all commonly used drilling and completion fluid additives is presented. Types of additives included are carbonate/bicarbonate pH buffer, biopolymers, synthetic polymers, clays, lubricants, weighting material, corrosion inhibitors, biocides, hydrogen sulfide (H2S) scavengers, antioxidants, oxygen scavengers, and defoamers.
Prior to the Formate Technical Manual becoming available for formate brine users, Cabot Corporation received numerous enquiries for information on corrosion characteristics of formates. In response, a separate review on metal compatibility of formate brines was commissioned, which is available to interested users of formate brines. Please note that this report is currently not a live document with regular updates. Cabot is happy to share any newer insight not included in this report.
Results from a variety of tests show that common elastomers perform as specified by the manufacturers when exposed to formate brines. Formate brines are buffered to maintain an alkaline pH during field use. Some elastomers are not compatible with alkaline fluids, especially at high temperatures. Examples are NBR (Nitrile) and FKM (Viton). These elastomers should not be used with buffered formate brines. Results from a variety of elastomer compatibility tests are summarized, and general guidelines are provided for elastomer performance in formate brines.
Material compatibility is important not only in the high pressure high temperature downhole environment, but also in surface tanks, pits, and flowlines. Over the years, a whole range of compatibility testing has been performed on materials such as glass, tank linings, subsea control fluids, thread compounds, and flowline gate sealants. The results of these tests are presented.
Most people believe that no fluid can stabilize wellbores better than oil-based muds (OBM). However, this is not right. Due to the high osmotic forces that are experienced when the wellbore is contacted with the low water activity cesium and potassium formate brines, the wellbore gains additional strength. This combined with the exceptionally high ROPs that have been reported, make formate brines probably the best shale drilling fluids in use today. The mechanisms involved in borehole instability and how formate brines prevent this from happening are explained. Methods for testing borehole stability are described and results of shale-stability testing in formate brines shown. Relevant field experience with formate brines published in open literature is reviewed.
During drilling and completion, well construction fluids circulating in the wellbore are in contact with many minerals under conditions of high temperature and pressure. Therefore, it is important to have a detailed knowledge of how the fluids interact with minerals under down-hole conditions. All known solubility data of minerals in formate brines have been collected and reviewed. Solubility data are also included for various clays, silicates, galena, hematite, ilmenite and calcium carbonate.
Formate brines have excellent hydrate inhibition properties due to their very low water activities. In spite of increased popularity of formate brines as well construction fluids over the past fifteen years, no hydrate prediction model has yet been developed for these brines. A limited number of measured hydrate equilibrium temperatures in formate brines are presented here. Comparison of hydrate inhibiting properties of formate brines with well-known hydrate inhibitors such as MEG, MEOH and calcium chloride, indicate that they are very similar.
Cesium, potassium, and sodium formate salts are not only soluble in water; they are also extremely soluble in many non-aqueous solvents. Results of solubility tests completed on sodium, potassium and cesium formate salts in five different non-aqueous solvents (ethylene glycols, propylene glycol, glycol ether, and glycerol) are presented. The results show that cesium formate dissolves in non-aqueous solvents to form high-density water-free fluids up to 2.22 g/cm3/18.53 lb/gal. Potassium and sodium formate salts can form non-aqueous fluids with moderately high density.
Part C: Formate Field Procedures and Applications
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Cesium is a limited resource, which makes cesium formate brine more expensive than other high density brines. It is therefore important that as little cesium formate as possible is lost to the environment, and that the brine is reclaimed with as little losses as possible. Analyses of the complete life cycle of high-density formate brine fluid is presented, including supply, application, return, and reclamation. Detailed guidelines for planning and preparation, supply, rig storage and surface handling, wellbore operations, sub-surface exposure, brine recovery and return, and brine reclamation are provided.
Most standard fluid test procedures used for heavy brines (API RP 13J) and water-based drilling fluids (API RP 13B-1) are also valid for formate brines and fluids. However, there are a few tests that are not valid for formate fluids and alternative formate-specific test methods have been developed. There is also one standard test – the retort test – that for safety reasons should never be used in formate brines. A list of the standard tests is provided that specifies clearly which tests are recommended for formate fluids and which ones are not.