There is no end to the great ideas that come from our creative and innovative industry; unfortunately, the uptake of many of these ideas seems to move at geologic speed.
Every month, the editors of Hart’s E&P publish Tech Watch and Tech Trends, two features designed to inform our readers about interesting and potentially beneficial innovations. Thinking about this, two absolute winners pop to mind — Cameron’s DC subsea production and control system, and NationalOilwellVarco’s Hex Pump.
These provided clear benefits and solved major challenges facing the offshore industry. Yet their actual implementation seemed to take eons.
Happily, both these systems have finally broken through the “no new technology” ceiling that has characterized the oil industry for decades and are now finding a foothold in the marketplace. The slow-daptation of technology has become an industry icon. Here’s a classic example.
Today, every well drilled anywhere is logged, sometimes with very sophisticated combinations of sensors, acquisition techniques, and real-time telemetry. Yet in the 1930s the Schlumberger bothers went home to France discouraged that their inventions would never gain acceptance. One man, a determined pioneer named E.G. Leonardon, stayed behind, even writing his bosses that he would forgo his salary, so convinced was he that well logging had a future in America. The brothers were called “those crazy Frenchmen,” and worse. And it was a toss-up who was craziest, the Schlumbergers or Leonardon. Yet, in the end, they were all proved right. Vindication is sweet.
So, what’s new?
As a footnote to 2009, we are writing about some new technologies particularly beneficial to production. We know they are winners because in most cases several providers are offering them, and business is booming. That’s a pretty good sign that a technology will be successful. We close with two ideas that are extremely innovative and thought-provoking, although they are not yet universally offered. Time will tell.
The first technologies involve seismic. Usually thought of as an exploration tool, seismic has evolved into a major production technology.
4-D seismic technique
Time-lapse, or 4-D, seismic is a natural evolutionary technique enabled by improved acquisition geometry and powerful processing capability. According to one of its pioneers, Statoil, the key to 4-D is repeatability. Today’s shots must precisely mimic yesterday’s so that a valid comparison can be made from which changes in reservoir drainage can be inferred. Some early techniques sought to ensure 100% repeatability by establishing an array of ocean-bottom sensors or nodes that were permanently fixed to the seabed and thus did not move between surveys. This technique worked reasonably well but was fairly expensive, and unfortunately it was also subject to accidental uprooting by fishing boats unknowingly dragging their anchors across the array.
Other acquisition providers sought repeatability by controlling the positions of their seismic streamers or, alternatively, accurately monitoring the positions of each hydrophone as each shot was fired. Sometime both techniques were used, and high- quality 4-D images resulted in most cases. Recently, on what was billed at the time as the world’s largest area 4-D seismic project, sea, wind, and current conditions were so severe that even steerable streamers feathered beyond limits. In an innovative processing technique, multiple shot-receiver combinations from different vintage surveys were matched, and those with closest geometric affinity were used to make the time-lapse comparison. According to the operator, as many as 20 well plans were altered as a result of the 4-D survey result, saving the operator millions in potentially dry or sub-optimal holes.
Incremental improvements in 4-D acquisition and processing have collectively made a dramatic improvement in survey quality, interpretability, and fidelity. The technique has been used successfully in many of the most prolific offshore areas of the world with excellent results.
Real-time microseismic fracture mapping
The early use of microseismic fracture mapping was to map the propagation pattern of hydraulic fractures and use the data to plan subsequent fracture jobs. But with the advent of real-time processing, the fractures can be observed as they propagate, opening up vast opportunities. Principle among these is avoidance of geohazards. With real-time fracture imaging, aquifers can be avoided that would flood the well with water, faults can be avoided that might communicate with gas or water zones, and fracturing into offset wells can be avoided.
But the most important benefit of real-time fracture mapping is the ability to alter the pumping schedule for the stage being fractured to ”steer” the fracture in a different direction. This can be accomplished by the tactical use of diverters, for example, based on real-time observations as the fracture propagates.
Microseismic fracture mapping has enabled an interesting new technique called “Zipper-Frac” or “Simul-Frac,” whereby adjacent wells are fraced either simultaneously or alternatingly, in sequence. By holding frac pressure on one well while the adjacent well is being fraced, the fractures tend to avoid each other because of the stress pattern set up in the pressured-up well. In the Zipper technique the alternating wells are fraced in sequence, resulting in a maximum of new reservoir rock exposed.
Water treatment and reuse
The booming hydraulic fracture treatment business, particularly popular in the stimulation of shale gas wells, involves thousands of gallons of water. Following the treatment, much of the water flows back to surface, but until now it has been unsuitable for reuse. Because of the scarcity of water in many areas, the industry has taken the initiative to treat the frac water so it an be reused. Various techniques have been developed with increasingly optimistic results.
Because produced water from wells must be disposed of (it cannot be used for irrigation, dumped into rivers or lakes,or even the sea), companies are looking for ways to treat produced water for use as fracturing fluid. Solutions have been proposed by the fracturing companies themselves as well as numerous oilfield chemical producers.
A technique proposed by General Electric involves separating the water into two volumes — one, amounting to about 30% of the total volume, would be saturated brine for disposal, while the other 70% would be suitable for reuse. Dow Chemical has just announced its BioPetroChean water treatment that targets both the refining and the produced water treatment markets. While this treatment cleans up the water and eases disposal issues, it is not clear whether that makes the water reusable in fracture treatments, although according to the company, effluent is “virtually pure.” Because the need is so great, other providers are expected to recognize this market opportunity and bring forward new solutions. There is little doubt that enabling produced water to be used in slickwater fracs would solve two problems very elegantly.
Intelligent pumps enable improved asset management
An increasing number of wells are produced using electrical submersible pumps (ESP). In the oil business, pumps are used to lift the oil to surface. In the gas business, pumps are used to dewater the wells so more gas can flow to surface.
ESPs have experienced a difficult evolution. When they work, they work very well, but in the early days, failures were common. Over the years ESP reliability has improved to acceptable levels; still, operators would like to improve their reliability. At the same time to properly manage a reservoir it is necessary to understand the performance of each well, whether it is a producer or an injector.
The pump industry now offers instrumented ESPs that contain one or two sensor packages. The well performance package measures temperature, pressure, and flow rate. The pump performance package measures such things as motor winding temperature, vibration, and intake and output pressures. Data are multiplexed and telemetered up the power cable. The measurements, coupled with those measured at the surface power supply, provide a wealth of information to the operator.
By monitoring all the pumps in a field, equipment failures can sometimes be anticipated and remedied before serious collateral damage occurs. Often, downtime can be minimized because operators learn to recognize the warning signs of an incipient failure and mobilize a replacement pump so the well is down only for the time necessary to pull and replace the pump. Pump problems often cause motor problems, but not vice versa. So if a pump problem-sign is detected, the pump can be pulled before it freezes up and burns up the motor.
A more sophisticated operation involves monitoring well performance. This has two main benefits. The monitors have the ability to make minor adjustments remotely to pump speed to keep it operating at peak efficiency — they can even shut it down remotely if necessary. By monitoring an entire field, only those wells that are performing badly are reported, so the operator’s engineers only have to focus on the few problem pumps, not the hundreds of good pumps. This leaves them free to work on other issues.
Intelligent pumps can pay for themselves in a very short time. They are becoming increasingly popular, and the technique has spread to other types of artificial lift.
Electromagnetic Pulse Stimulation
Of all the stimulation techniques launched recently, this one seems the most innovative. BJ Services announced success in more than 60 electromagnetic treatments of producing formations to alleviate plugged pore throats and improve reservoir wettability. Called EcoWave, the tool transmits high-frequency radio waves and microwaves into the formation at low power to remove and inhibit organic deposition that reduces permeability. Treatments target the near-wellbore region where most of the plugging occurs, and treated zones last for up to three months.
Elegant in its simplicity, the treatment requires no chemicals, no pumping equipment, and no large crews on location. A portable generator/ amplifier, power source, and antenna are all that are required. The antenna is deployed down the tubing or tubing/casing annulus through the wellhead. Energization time takes from 30 minutes to two hours, and the electromagnetic energy propagates through the antenna and into the well bore, altering the molecular structure of the deposits. This inhibits agglomeration and allows the deposits, which can include such common problems as paraffin, to be easily flushed from the well bore.
According to the company, the economic benefits of the treatments are enhanced by safety and environmental benefits compared to alternative techniques such as harsh chemicals, hot oil, or hot water treatments.
Experience to date is good, with treated wells’ production ramping up from 20% to as much as 120% compared to chemically treated offset wells. On one well, the subsurface pump had become clogged, shutting off production completely. After two hours of EcoWave treatment, the pump was freed up, and the operator was able to resume production. In two wells near Hobbs, N.M., hot oil treatments were largely ineffective. The wells were treated with EcoWave — one’s production rate ramped up 57%, and the other’s was boosted 126%. Both wells stabilized and maintained the increased rates for several months.
Degradable fiber diverters
Hydraulic factures initiate at the point of least resistance. If this is not where the engineer wants the fracture, a diversion medium must be introduced. An alternate application is in the case where a number of fractures are desired from the same set of perforations. In this case, as each fracture reaches its desired length, the diverter is deployed, causing a fracture to initiate elsewhere. Lastly is the case of a re-frac job, where the treatment appears to be entering the old fracture. A diverter can plug of the old fracture and allow the energy to shift to another spot.
But if the diverter media is permanent, it defeats the purpose. Accordingly, Schlumberger has developed degradable fiber diverter media that plugs up a fracture and causes diversion but which degrades after a short period, leaving all fractures open to production flow or injection, whichever is desired.
The fiber is completely benign and has no lasting negative effect on either the well or production equipment. It can be deployed on-the-fly as microseismic monitors indicate that diversion is appropriate.
What’s your most interesting new technology?
These ideas intrigued us. Several have proliferated widely. Others are in their infancy. How they are received depends on delivery of tangible benefits. Let us hear from you about your favorites.