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While formation damage is typically a problem affecting the productivity of well, it can also pose problems for injection. Understanding the causes of this type of formation damage is important so that efforts to prevent it can be undertaken. This page discusses the types of formation damage that affect injection wells. In such projects, the cost of piping and pumping the water is determined primarily by reservoir depth and the source of the water. However, water treatment costs can vary substantially, depending on the water quality required.
Steam generation for the purposes of thermal recovery includes facilities to treat the water (produced water or fresh water), generate the steam, and transport it to the injection wells. A steamflood uses high-quality steam injected into an oil reservoir. The quality of steam is defined as the weight percent of steam in the vapor phase to the total weight of steam. The higher the steam quality, the more heat is carried by this steam. High-quality steam provides heat to reduce oil viscosity, which mobilizes and sweeps the crude to the producing wells.
Water management can significantly add to the cost and environmental footprint of oil production and innovations in water management can provide significant economic and environmental gains. New treatment technologies make recycling of water for hydraulic fracturing possible. Methods for recycling fracking water include anaerobic and aerobic biologic treatment; clarification; filtration; electrocoagulation; blending (directly diluting wastewater with freshwater); and evaporation. Generally, anaerobic treatments on wastewater are implemented on concentrated wastewater. Anaerobic sludge contains a variety of microorganisms that cooperate to convert organic material to biogas via hydrolysis and acidification.
Shearing of production fluids creates tight oil/water emulsions, including small droplets of oil in water and small droplets of water in oil. Small droplets rise very slowly and are often not adequately separated in a given residence time. This can overwhelm downstream equipment unless additional steps are taken such as increasing chemical dosage, adding or increasing heat, or removal of the emulsion for separate treatment--all of which will increase operating and capital expenses. For our purposes, we consider only the removal of oil from water in a water treatment system. Removal of water from oil, as in oil dehydration, will be discussed elsewhere. The article is simply a review of basic droplet formation due to shearing from pipes, valves, and pumps. It is intended to remind engineers that the decisions made upstream can have a grave consequence on downstream separation equipment performance. The article focuses mostly on the sources of shear, the relative magnitude of shear, and the consequence on the oil droplet size. Details regarding oil droplet size distribution is outside the scope of this article. Instead, the focus is on just one parameter of the droplet diameter distribution, the maximum droplet diameter. Also, the effect of smaller oil droplets on water treatment equipment is not discussed in detail.
Production separators, whether they are two-phase, three-phase, horizontal, or vertical, are the backbone of the upstream facility. The performance of the separator(s) is key for a facility to meet both its export basic sediment & water (BS&W) and produced water specifications, as well as for ensuring that the compression system remains clean and liquids are minimized. The primary purpose of a production separator vessel (as well as scrubbers, treaters, or slug catchers) is to partition and separate the distinct fluid phases: gas, oil/condensate, and water. The gas stream exiting the separator should have minimal liquids content, the oil stream should have trace amounts of water, and the produced water stream should contain parts-per-million (ppm) levels of oil. In reality, the fluids entering the separator are likely to have additional "phases," in the form of sand/solids, foam, and emulsion, which could be a water-in-oil emulsion or oil-in-water (OIW) emulsion (referred to as a reverse emulsion). It is these other phases that make separation even more challenging.
As demand for energy continues to rise and conventional sources become more scarce, oil and gas companies are under pressure to pursue production through unconventional methods and enhanced oil recovery (EOR) technologies. Nearly all unconventional and enhanced recovery methods involve significant amounts of water and, therefore, specific technical and management challenges related to water. Not only does this trend have significant implications for the water treatment business, it also calls for a new level of cooperation between the industrial water treatment sector and the oil and gas industry. With the growing and urgent need for better, commercially effective ways to handle produced water from unconventional production, the question of how the oil and gas industry will be able to access the best that the water treatment industry has to offer now shows the beginnings of a possible answer. The water treatment industry has started to appreciate the complexity of water challenges in the oil and gas industry. Likewise, the latter has begun to look to the former for solutions.
Innovation in oil extraction, particularly around water, has made the concept of "peak oil" a distant memory. New extraction methods propelling the future of oil and gas depend heavily on water as a critical input--shale developments and waterflood enhanced oil recovery (EOR) are two examples. Extraction using water has opened up substantial new hydrocarbon resource plays. However they can produce four times more salty water byproduct than oil. Operators have become experts at reusing this water, in some cases over 95% of it.
Water management in shale plays is an extremely competitive business. This is most evident in the Permian Basin where companies work tirelessly to minimize operating costs in order to contract new capacities and fill their capital-rich infrastructure. These players are under enormous pressure to evaluate every component of costs and wring out excesses. While traditional operating expenses (OPEX) are heavily scrutinized, a full picture of profitability in water management is gained only after comprehensively examining the unique aspects of their overall business model. Traditional OPEX components in produced water management include labor, chemicals, consumables, infrastructure maintenance, transportation, disposal, solids handling, and power and other utilities.
A long-time energy industry executive and chemical engineer has built a new water treatment system that he says can increase recovery rates from shale wells without using chemicals and will recycle all the water used in the process. "The trick is to use a high concentration of positive ions--it changes the characteristics of the shale," said Joe Munisteri, founder and president of MBL Industries. He explained that his electromagnetic technology will flood fracturing water with an excess of positively charged particles and selectively trigger a reaction with the shale's calcite minerals--transforming them into a much more brittle mineral called aragonite. Munisteri believes this altered state will open up calcite-sealed natural fractures and other pathways to allow oil and gas to flow freely. MBL is seeking pilot opportunities and is in talks with an independent producer that operates in the Eagle Ford Shale of Texas to test its novel hydraulic fracturing system on two wells: one that is depleted and one that is drilled but uncompleted.