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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.
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.
When oil demand vaporized, oil sands producers quickly had to cut 1 million B/D of production. "Our strategy is to keep as many barrels away from the train wreck as possible to minimize negative cash margins," said Rob Peabody, chief executive officer for Husky, during a call with analysts. Now that oil prices are back near the levels where oil sands producers can consider restarting them, it is time to answer the question: "Can they turn them off and on?" said Scott Norlin, a research associate at Wood Mackenzie. Executives with major oil sands companies said they can turn them off and on without missing a beat based on lessons learned from big cuts in recent years. "So, will there be some impact? Maybe, but very little," said Tim McKay, president of Canadian Natural Resources Ltd. (CNRL), during its first-quarter earnings call.
A series of unexpected circumstances have intersected to drive oil markets down, causing myriad challenges for operators and service companies alike. A virus pandemic erupts, shutting down global economies and thus the demand for oil. Ongoing disagreements between OPEC, Saudi Arabia, and Russia on a response strategy and increased production sees global crude prices drop to the $20 range, something we have not seen in decades. Compounding the crisis in North America is the market influence over the past few years, which drove operators to focus on cash flow and profitability over production and capital discipline with limited access to equity and additional debt. Operators will need to work closely with service providers to once again make step changes in optimizing value, improving efficiency, and eliminating downtime and wasted resources.
This chapter concerns the use of water injection to increase the production from oil reservoirs, and the technologies that have been developed over the past 50 years to evaluate, design, operate, and monitor such projects. Use of water to increase oil production is known as "secondary recovery" and typically follows "primary production," which uses the reservoir's natural energy (fluid and rock expansion, solution-gas drive, gravity drainage, and aquifer influx) to produce oil. The principal reason for waterflooding an oil reservoir is to increase the oil-production rate and, ultimately, the oil recovery. This is accomplished by "voidage replacement"--injection of water to increase the reservoir pressure to its initial level and maintain it near that pressure. The water displaces oil from the pore spaces, but the efficiency of such displacement depends on many factors (e.g., oil viscosity and rock characteristics).
There are many opportunities to modify and improve the waterflood as data are acquired and analyzed. Applying material balance concepts means that initially there is "reservoir fill-up" if the reservoir previously had some years of primary production. During this period, the reservoir is repressured to its original reservoir pressure because the injected-water volumes will be substantially greater than the produced-fluid volumes. Thereafter, the waterflood will be operated as a voidage-replacement process. The earliest waterflood monitoring techniques were developed soon after the first field applications of waterflooding; they were based on simple plots, maps, and calculations.
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.
The use of real-time downhole monitoring is an effective approach to achieve this optimization. The use of downhole distributed-temperature sensing (DTS) and array-temperature sensing by use of fiber-optic technology has led to instrumented wells that enable data access on a real-time basis, leading to better control of operations, and to optimizing the steam process. Also, fiber-optic technology enables measuring pressure and temperature over the same fiber and in close proximity along the wellbore. At reservoir conditions, bitumen is essentially immobile, and recovery of these highly viscous fluids requires viscosity reduction, often by applying heat. The SAGD process is an effective recovery method for heavy oil and bitumen.
The rising tide of produced water in the Permian Basin is requiring operators to re-engineer how they manage water. One big difference in the Permian is that water production from unconventional reservoirs exceeds output from most other plays, particularly in the Delaware Basin. Prolific water production has long been a given in conventional fields there, but most of that could be reinjected to maintain production, which is not an option in the ultratight rock. Instead, billions of gallons of produced water have been pumped into saltwater disposal wells in shallow formations, such as the San Andres, significantly increasing the pressure drillers encounter, creating a hazard for drillers moving in and out of them from lower-pressure zones. To isolate the higher-pressure zones passed on the way to the Wolfcamp, operators have increased the number of strings of casing used from three to four.
Frac water demand in the Permian Basin is high and shows no signs of slowing down. According to Rystad Energy, operators by the end of this year will be using more frac water in the Permian than what was used in every US basin combined in 2016. The Delaware Basin accounts for 17% of the frac water market, and of that Rystad identified 60% of the market share coming from the top 10 operators in the Permian (Pioneer, Concho, EOG, Apache, Oxy, Exxon Mobil Corp., Anadarko, Diamondback Energy, Chevron, and Devon). More than 2 billion bbl of produced water comes from the Permian, and flowback water has increased 300% since 2016, but Rystad's vice president of shale research said the water treatment market has not grown at a similar rate. Speaking at an information session to discuss developments in oil and gas, Benjamin Stewart addressed the factors behind the growth of the water disposal market in the Permian as well as the state of the wider treatment market.