It has been known since the 1930's that concentrated brines release barium into solution from barite. The amount of barium released into solution is a function of the molar salt concentration, brine type, temperature, and pressure. Brines containing very high molar concentrations of solute are the most effective at solubilizing barite in well operations. Given the HSE hazard posed by fluids containing soluble barium it is important to know exactly what levels of this heavy metal may be present in high molarity oilfield brine systems that have been contaminated with barite.An extensive test program has now been conducted to provide new and reliable information on the soluble barium content of potassium-and cesium formate brines that have been exposed to analytical grade barium sulfate at elevated temperatures and then cooled. The effects of formate concentration and the ratio of cesium to potassium in the formate brines were investigated. The brines were tested with and without the addition of carbonate/bicarbonate pH buffer, as a function of exposure temperature and exposure time.The results of this research confirm results of previous research reported by Shell, indicating that up to 3,500 mg/L of barium can be released from barium sulfate at 100°C (212°F) in the most concentrated potassium formate brines. However, the good news is that soluble barium levels are low in all formate brines that contain carbonate/bicarbonate pH buffer. This is because any dissolved barium will precipitate out as barium carbonate, which is barely soluble in concentrated formate brines.This new insight into the mechanisms of barite dissolution in buffered and unbuffered formate brines could open the door for the formulation of more advanced fluids for filter cake removal and scale dissolution applications.
Deep HPHT gas/condensate wells drilled and completed in open hole with cesium formate fluids clean-up naturally over hours and sometime days after initial production start-up as the wells unload water-based fluids and filter-cake from the reservoir zone. Following natural flowing clean-up during the start-up phase the wells tend to be highly productive, with low skins, and over the long-term those fields developed entirely and solely with cesium formate fluids have a reputation for delivering the recoverable hydrocarbon reserves projected in the operators' original business plans. Laboratory core flooding tests with cesium formate fluids attempt to simulate real well clean-ups by applying drawdown pressures across the cores to create a cleansing flow of gas or oil to bring the rock permeability back to original native levels. Such attempts are usually successful in cores flooded with clear cesium formate brines, but it is rare to hear of cores that have cleaned up 100% after long duration exposure to cesium formate drilling fluids without subsequent mild stimulation with water or dilute acid. The persistent lack of congruence between observed well clean up performance and core flooding test results with cesium formate drilling fluids suggests that the attempted laboratory simulations of natural well clean up under drawdown might be inadequate or flawed in some way. One point of concern thought worthy of further investigation has been the duration of the drawdown-induced gas or oil flows applied in laboratory core flood tests to restore permeability. Wells have the opportunity to gradually clean up over years during production while laboratory clean ups by drawdown may only be applied for minutes or hours. The objective of the study described in this paper was to review old core flood test data to see how quickly the simulated well clean-up procedures restored original permeability in tight gas-bearing sandstone cores after exposure to high-density cesium formate fluids for at least 48 hours under HPHT conditions. Plugs of gas-bearing low permeability (2-20 mD) sandstone containing simulated formation water at irreducible water saturation were exposed to overbalanced cesium formate fluids for 48-96 hours under HPHT reservoir conditions. The plugs were then subjected to drawdown regimes with nitrogen gas, under HPHT reservoir conditions, to simulate formation and filter-cake clean-up of an open-hole deep gas well completion at production start-up. Fluid and gas flow rates, and differential pressures across the plug, were logged whenever flow was induced through the plug, to allow estimation of the relative permeability changes in the rock throughout the test sequence. Results were compared for HPHT core flooding tests with: 10 pore volumes of SG 2.20 cesium formate completion brine pushed through 2 mD sandstone plugs at 200° C and high pressure, followed by a 48-hour static soak period under the same conditions.10 pore volumes of SG 2.20 cesium formate completion brine pushed through 20 mD sandstone plugs at 175°C, followed by a 48-hour static soak period under the same conditions.SG 1.76 potassium/cesium formate drilling fluid circulated at 500 psi overbalance for 48 hours across the face of a 20 mD sandstone plug at 150°C, and then left static for a further 48 hours, resulting in 1.2 pore volumes of fluid loss through the core. The straight cesium formate brines were removed quite promptly, typically within 15-30 minutes, from the 2-20 mD rock cores during drawdown. In the test with 20 mD sandstone plug and cesium formate drilling fluid the drawdown pressures were ramped up in stages from 1 psi to 100 psi during the clean-up phase but the rock plug was slower to regain its permeability. After 96 minutes of drawdown the plug had only recovered 79% of its initial relative gas permeability and clearly it was still in the process of cleaning up. The test results provide new information about the clean-up rate of low permeability rock cores invaded by heavy cesium formate fluids under HPHT conditions and subjected to drawdown with gas.
Xanthan gum is a non-damaging viscosifier and fluid loss control agent commonly included in reservoir drill-in, completion and workover fluid formulations. One of the key benefits offered by xanthan in these applications is that it is not an especially robust polysaccharide and under downhole conditions it will eventually self-break through molecular collapse and/or depolymerisation reactions. With only a temporary presence in the filter cake and formation invaded by filtrate, xanthan can never pose a serious or permanent threat to oil and gas production but clearly it would be good to be able to control and manage the rate at which it degrades. The rate at which xanthan degrades downhole is a function of the temperature, the presence of oxidants and the ionic environment. The purpose of the experimental program described in this paper was to measure the rate of natural self-breaking of xanthan under different temperature conditions when dissolved in various water and brine systems containing formate and halide ions. A simulated North Sea formation water and a low-sulfate seawater were included in the test program. The samples were dynamically and statically aged for periods up to 12 months, and their degree of natural self-breaking was tracked by viscosity measurements. Several other classes of polysaccharide were tested in the program, either alone or in combination with xanthan. The tests confirmed that at temperatures in the range 124–170°C (255–338°F) xanthan and the other polysaccharides all degraded over time and the resulting "broken" fluids had low viscosities. It was found that the self-breaking rate varied hugely with brine type and concentration. Concentrated formate brines, rich in antioxidants and high molar concentrations of water-structure making ions, allowed steady rates of polymer breaking over weeks and months while the same polysaccharides dissolved in brines containing significant amounts of sodium bromide degraded very quickly. These results suggested that clear brine systems of any density within the compatibility limits of the blended components could be engineered to self-break within a set period of time by blending formate and sodium bromide brines in appropriate ratios. Degradation tests at 124°C (255°F) of xanthan in a typical North Sea formation water and a low-sulphate seawater, showed very rapid self-degradation, resulting in hardly any remaining viscosity after only 4 days of ageing. It seems likely that xanthan gum and other polysaccharides that are stabilized in formate brines, will lose their viscosity rapidly if contacted by formation water or well injection water. In fact, an overflush of the filter cake and near wellbore formation with any low salinity fluid would make an effective breaker system for xanthan in the applicable temperature range. The learning points from this study offer a solution to the problem of filtrate retention as an artifact in laboratory coreflood tests of viscosified brine-based fluids. Not exposing the fluid to the reservoir temperature for a realistic time period between invasion and drawdown may leave some viscosified brine in the pore space and in the filtercake, that is hard to remove during the standard drawdown time. Such retained filtrate has an adverse effect on the core's water saturation and thereby on the effective permeability to hydrocarbons.
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