The increasing demand for energy has extended the development horizon towards relatively tighter formations all over the world. In Saudi Arabia, hydrochloric and organic acids have been extensively used to enhance well productivity or injectivity in low permeability formations. However, the use of these acids was associated with severe formation damage, which is attributed to acid/oil emulsions and/or asphaltene precipitation in some of the low permeability carbonate reservoirs. Consequently, a detailed study on different factors that influence the acid/oil emulsion and asphaltene precipitation mechanism was carried out for these reservoirs. Several compatibility studies were conducted using representative crude samples and different acid systems such as HCl and formic acid. The experiments were conducted at various temperatures up to 240°F using HP/HT aging cell for both live and spent acid samples, where some of the experiments included anti-sludge, iron control and demulsifier chemical additives. In addition, another set of experiments was performed in the presence of ferric ions (Fe3+). The total iron concentration in these experiments varied between 0-1,000 ppm. The results obtained from this study have revealed that the acid systems were not compatible with several representative oil field samples. The amount of asphaltene precipitation and the stability of formed emulsions increased significantly in the presence of ferric ions. Several wells have already been acidized and damaged prior to initiating this study. This paper discusses different tests conducted to identify, quantify and treat acid-oil emulsions/asphaltene precipitation in tight carbonate reservoirs. It also provides details of a special solvent treatment fluid recommended to revive dead wells which were damaged by acid-induced emulsion and asphaltene precipitation.
An impermeable mud cake layer, created on the formation face while drilling may be favorable for drilling operations but detrimental to well productivity. In vertical high pressure wells the layer is cleaned out while flowing back the well at adequate pressure drawdown. On the other hand, low pressure differential at the sand face in horizontal wells makes well cleanup treatments a necessity. Not all filter cake components are acid soluble. Commonly used inorganic acids and oxidizers are very reactive and cause uneven filter cake removal, which can affect the well's performance. As a result, there was a need to evaluate slow-reacting chemicals that can produce delayed uniform filter cake removal in horizontal wells. These treatment chemicals vary from the nonreactive acid-free microemulsion fluid systems to the weak organic acids, acid precursors, enzymes and chelating agents. The objective of this paper is to evaluate two chelating agent based treatments, NTA and EDTA, as filter cake removal treatments for a sandstone reservoir utilizing oil based mud (OBM) drill-in fluid (DIF) in Saudi Arabia. Coreflooding experiments were run under reservoir conditions to evaluate fluid-rock interaction. In addition, fluid-fluid compatibility was conducted between chelating agent and drill-in fluids base brines and between the chelating agent and formation fluid using high temperature, high pressure (HTHP) see-through cell. Solubility and static fluid-loss tests were conducted to evaluate the filter cake removal efficiency. Experimental results indicated that the NTA-based treatment was effective in removing up to 91% of the filter cake uniformly after soaking treatment for 24 hours. Fluid-fluid compatibility tests showed that the NTA-based chelating agent, when mixed with reservoir fluids, was free from precipitation or emulsion. On the contrary, mixing the chelating agent with the DIF carrier brine resulted in severe precipitation of insoluble permanently damaging byproducts. The laboratory study also observed that pH has a direct proportional relationship with the amount of precipitation. EDTA-based treatment results showed a removal efficiency of 93% after soaking treatment for 90 hours. Fluid-fluid compatibility tests showed that the EDTA-based treatment, when mixed with OBM DIF was free from precipitation or emulsion. On the contrary, mixing the chelating agent with the reservoir formation water resulted in severe precipitation of insoluble permanently damaging byproducts.
Mono and diamine compounds were synthesized from 1, 12-dodecanediamaine, and evaluated as acid corrosion inhibitors for coiled tubing steel. The inhibition behavior of these compounds in concentrated HCl acid was examined using a gravimetric method. Weight loss tests were conducted in 28 wt% HCl acid at 60, 70 and 80 o C for 2 hours. The results showed that both mono and diamine inhibitors exhibited a good protection efficiency for coiled tubing steel in 28 wt% HCl acid. However, monoamine compounds showed better performance. Addition of an intensifier was effective to enhance protection efficiency for both amine moiety compounds where more than 99% protection was obtained for some inhibitors. The effect of intensifier concentration on inhibition efficiency is also addressed in this paper. The results obtained are very promising and suggest that some of examined corrosion inhibitors have a good potential to be used in acid stimulation treatments of oil/gas wells.
It is challenging to control water production in horizontal wells or in vertical wells having oil and water produced from the same zone using conventional methods such as through-tubing bridge plugs or other mechanical means. Relative permeability modifiers (RPMs), known to selectively reduce the relative permeability to water with minimum impact on the relative permeability to oil or gas, are considered a promising technology for solving this problem. The current generation of RPMs, unlike the old ones, can tolerate high hardness and so have higher success rates. An extensive experimental work was carried out to evaluate three RPMs for water control in gas and oil wells. Test conditions included gas flow in sandstone cores with temperatures of up to 300°F, and oil flow in carbonate cores with temperatures as high as 220°F. The effect of initial core permeability to brine, RPM concentration, flow rate, and water-wetting surfactants on the effectiveness of RPM to reduce water production was investigated using sandstone and carbonate cores. Coreflood experiments were undertaken at downhole conditions. The end-point relative permeabilities to various phases were measured. A back pressure of 500 psi, an overburden pressure of 3,500 to 5,000 psi and flow rates of 0.1 to 5 cm3/min were used. The concentration of RPM polymers was monitored in the core effluent using total organic carbon (TOC) analyzer to determine polymer retention in the core. The results revealed that temperature adversely affected the effectiveness of all RPMs evaluated. A better reduction in permeability to water was obtained at 220°F compared to that obtained at 300°F. The use of RPM at the right concentrations was found to significantly reduce permeability to water. A better water reduction was obtained at higher polymer injection rates, which was attributed to flow-induced polymer retention. Adsorption of RPM polymer tended to alter wettability of a carbonate rock to more water-wet. This paper discusses the effects of the above parameters on the performance of RPM in sandstone and carbonate reservoirs, and it gives some recommendations for improving the success rate of these chemical applications in the field.
Quality of water used for injection is a very essential factor in preventing/minimizing formation damage potential and thus maintaining required injectivity. Also, injected water should be compatible with both rock and formation fluids minimizing risk of permeability impairment or flow assurance problems during the production phase. Assessing water quality is a prime step to prevent scale precipitation, fine migration and any negative impact resulting from water/rock interactions. Extensive experimental studies including HT/HP compatibility tests and coreflooding experiments were conducted to evaluate the effect of high (salinity, sulfates and bicarbonates) water samples on clastic and carbonate core plugs. The impact of rock clay content, fine migration and scale deposition on impairment of rock permeability was investigated. Compatibility and coreflooding tests were conducted on different water mixtures to optimize a water mixture having less effect on formation permeability. Experiments were conducted at temperatures up to 200°F and pressure 3,000 psi. Formation damage mechanisms were investigated using XRD and ESEM methods on precipitated scale due to fluid/fluid and rock/fluid interactions. HT/HP compatibility test results indicated that some of the examined water mixtures precipitated iron compounds when exposed to air. Oxygen scavenger was added to some water mixtures to halt iron precipitation before injection into the carbonate and clastic core plugs. Coreflood experiments showed permeability reduction in some of the core plugs, which was attributed to the precipitation of iron oxide/hydroxide compounds as, indicated from ESEM and XRD analysis. High sulfates and high bicarbonates content of some of the water mixtures precipitated compounds that contain both on the face and deep inside some of the tested plugs leading to reduction in permeability. This paper presents a qualitative and experimental water flooding analysis study conducted to assess interaction of different water/water mixtures on clastic and carbonate core plugs. It also investigates different formation damage mechanisms associated with water injection. It investigates interaction impact of water mixtures with examined core plug permeabilities.
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