Early U.S. settlements commonly were located near salt lakes that supplied salt to the population. These salt springs were often contaminated with petroleum, and many of the early efforts to acquire salt by digging wells were rewarded by finding unwanted amounts of oil and gas associated with the saline waters. In the Appalachian Mountains, saline water springs commonly occur along the crests of anticlines.[1] In 1855, it was found that petroleum distillation produced light oil that was, as an illuminant, similar to coal oil and better than whale oil.[2] This knowledge spurred the search for saline waters containing oil. With the methods of the salt producers, Colonel Edward Drake drilled a well on Oil Creek, near Titusville, Pennsylvania, in 1859.

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.

Most produced water contains salts that can cause problems in production and refining, when solids precipitate to form scale on process equipment. The salts also accelerate corrosion in piping and equipment. The salt content of crude oil almost always consists of salt dissolved in small droplets of water that are dispersed in the crude. Sometimes the produced oil contains crystalline salt, which forms because of pressure and temperature changes and because of stripping of water vapor as the fluid flows up the wellbore and through the production equipment. The salinity of produced brine varies widely, but for most produced water, it ranges from 5,000 to 250,000 ppm of equivalent NaCl.

Cold heavy oil production with sand (CHOPS) recovery processes generate large volumes of sand that must be managed. In Canada in 1997, approximately 330,000 m3 of sand (approximately 45% porosity sand at surface) were produced from CHOPS wells. Individual wells may produce as much as 10 to 20 m3/d of sand in the first days of production and may diminish to values of 0.25 to 5 m3/d when steady state is achieved. Sand grain size reflects most of the reservoir. There is little sorting or segregation in the slurry transport to the well; however, not all zones in the reservoir may be contributing equally at all times.

Production operations in coalbed methane (CBM) wells are not significantly different from other gas wells except for one important distinction. Conventional wells typically begin production with high gas/water ratios (GWR) that decrease with time, whereas CBM wells start with low GWRs that increase with time. This distinction requires that equipment and facilities for water handling and disposal be built at the start of a project, which requires significant lead time and capital investment. The initial operational goal of nearly all CBM wells is to depressure the reservoir by continuously producing water at a low flowing bottomhole pressure. This requires an artificial-lift system that can be modified as the gas rate increases and water volumes decrease.

It has been a few months since the collapse of the Vienna Alliance talks and the full, global extent of coronavirus (COVID-19) started to become apparent. While oil prices have improved somewhat and some optimism has emerged since then, it's clear that the damage wrought during that short stretch of time will be severe and long lasting. This is certainly true in US upstream activity, which will of course subsequently affect the water market. Our research suggests that US land drilling and completions (D&C) water demand will decrease 48% during 2020 as a result of the capital spending reductions leading to drastic reductions in D&C activity levels. However, with a rebound in activity expected in 2022, the overall D&C water market will in fact grow at a 7% compound annual growth rate from 2020 to 2024.

Pennsylvania-based shale-gas producer Range Resources announced today a new goal to achieve net-zero greenhouse gas (GHG) emissions by 2025. The company noted that the decision comes "in the face of an evolving energy landscape" and that it has committed to bolstering the transparency of its emissions data in sustainability reports. "With significant board guidance and oversight, we have reaffirmed ambitious near-term and long-term emissions reduction goals, which will ensure we are focused on maximizing every opportunity to further reduce our environmental and operating footprint," said Jeffrey Ventura, the chief executive officer, in a statement. Range's target is among the most aggressive to be established among pure-play onshore explorers in the US and is the latest evidence that the carbon-reduction plans adopted by international majors are trickling down throughout the oil and gas industry. The company highlighted that it already has made serious efforts in this regard and ranks as one of the lowest contributors to CO2 emissions in the sector, according to data from oil and gas consultancy Rystad Energy.

Gummy bears is one of the names for a gross mix of downhole junk that can foul a separator or clog tubing in the Woodford play in Oklahoma. The texture is often rubbery--the only connection to the gummy candy--and the color varies depending on whether the well's output tilts toward oil or gas. These "unusual semi-solid" accumulations were described in a 2015 Halliburton paper as containing hydrocarbons, sand, iron, fine particles from clay, and sometimes a bit of friction reducer--polyacrylamide to be exact (SPE 173594). The globs generally are seen at the surface after fracturing. When they are observed downhole, they have been pushed by the well's flow into "choke points" such as "perforations, tubing anchors, gas lift valves" downhole which are noticed when production declines, the paper said.

The plunge in well completions has exceeded the drop in the number of active drilling rigs, and operators are rethinking how they fracture wells now that oil is selling for half of what it did 6 months ago. For Mike Vincent, an independent consultant who teaches fracturing courses, it led to a change in his lesson plans. "One class I am teaching this summer is titled, 'How should we complete a well in a low-cost environment?'" he said. "We need to do things differently. There should be a different optimal design if a well is drilled when oil is USD 50/bbl versus USD 100/bbl." Financially the goal is simple: find a way to earn an acceptable profit on each dollar invested.

The design of a waterflood has many phases. First, simple engineering evaluation techniques are used to determine whether the reservoir meets the minimum technical and economic criteria for a successful waterflood. If so, then more-detailed technical calculations are made. These include the full range of engineering and geoscience studies. The geologists must develop as complete an understanding as possible of the internal character of the pay intervals and of the continuity of nonpay intervals.