Hydrocarbons occupy a vital role in our life and continue to play an important role for many more years to come. We need to follow all technological innovations to continue our productivity standards to achieve our production targets. Let us extend our vision to achieve this mission.

Thursday, March 20, 2014

Happy Birthday, Fracking!

Happy Birthday, Fracking!


Happy birthday, fracking! What a fantastic, 65-year ride it has been – and here's to another 65 years and more.


Advanced hydraulic fracturing and horizontal drilling launched an oil and natural gas renaissance in this country – bringing dynamic job creation, economic stimulus that radiates well beyond the oil and natural gas industry proper and greater energy security. Thanks to fracking, the United States is an energy superpower that, with the right policies, can harness its vast resources to ensure a significantly better future for its citizens while reducing energy-related tension across the globe.


More on the benefits of hydraulic fracturing below, but first let's take a look at how we got here. We celebrate the first commercial use of hydraulic fracturing 65 years ago on March 17, 1949, conducted by 


Halliburton in Stephens County, Okla., and Archer County, Texas. But the roots of the fracking story stretch back to the 1860s. In a 2010 article for the Society of Petroleum Engineers' Journal of Petroleum Technology (JPT), NSI Technologies' Carl Montgomery and Michael Smith write that energy pioneers experimented with oil well "shooting" that would "rubblize" oil-bearing rock to increase flows. Various methodologies were used to fracture rock formations over the years until Stanolind Oil, a division of Standard Oil of Indiana, conducted the first experimental "hydrafrac" in 1947 in Kansas. It involved pumping fluid carrying "propping agents" at high pressure into a well to create fractures that could be held open to free oil and natural gas in the rock. JPT:


A patent was issued in 1949, with an exclusive license granted to the Halliburton Oil Well Cementing Company (Howco) to pump the new Hydrafrac process. Howco performed the first two commercial fracturing treatments—one, costing $900, in Stephens County, Oklahoma, and the other, costing $1,000, in Archer County, Texas—on March 17, 1949 … In the first year, 332 wells were treated, with an average production increase of 75%. Applications of the fracturing process grew rapidly and increased the supply of oil in the United States far beyond anything anticipated. Treatments reached more than 3,000 wells a month for stretches during the mid-1950s.


Halliburton took the investment risks, ventured forth and marked the opening of a new era in energy development. From "The Legend of Halliburton":

The investment was risky for Howco, with hundreds of thousands of dollars at stake. Bob Diggs Brown, former vice president of sales and advertising, said Howco's chief engineer, Bill Owsley, was convinced of the concept's potential. "It wasn't a cheap prospect at a point in time when the process hadn't really been proved. But Bill Owsley, bless his heart, was just right for Halliburton. He convinced Mr. Halliburton."


The onset of the modern shale revolution came with the marriage of advanced fracking and horizontal drilling, allowing operators to sink a well a mile or more deep before gradually turning it from vertical to horizontal – often stretching out another 6,000 feet or more and allowing a single well site on the surface to accommodate a number of wells. Today, according to the U.S. Energy Information Administration (EIA), fracking is responsible for 3.5 million barrels per day of oil production (45 percent of U.S. total) and 40 billion cubic feet per day of natural gas production (60 percent of total).


EIA's Annual Energy Outlook 2014 Early Release shows how important hydraulic fracturing is to our energy present and future. So-called "tight oil" developed from shale and other tight-rock formations with hydraulic fracturing will play the major role in letting the U.S. near historic oil output levels over the next couple of years, EIA projects:




 

Similarly, EIA says natural gas from shale will lead overall U.S. growth:




 

When data for 2013 is complete, EIA estimates the U.S. will be the world leader in combined oil and natural gas production for the year. Thanks, fracking.

These numbers only suggest the impact that energy safely and responsibly developed with hydraulic fracturing is having and will have on the lives of individual Americans and our broader economy. Numbers from an IHS study help complete the picture:


In 2012, unconventional oil and natural gas from fracking and energy-related chemicals activity supported more than 2.1 million jobs.


By 2025 this activity will support nearly 3.9 million jobs.


In 2012, energy from fracking and related chemicals activity contributed almost $284 billion to GDP. By 2025 the contribution could approach $533 billion.

Abundant, affordable energy from shale has helped fuel a U.S. manufacturing resurgence – as companies fill orders for materials and equipment used in energy development and as they and others realize energy savings in their operations. Overall, the U.S. manufacturing sector has added more than 500,000 jobs since 2009, IHS says.


For U.S. households, the energy surge made possible by fracking has produced household savings through lower natural gas prices. IHS estimates that in 2012 this meant an increase in real disposable income of more than $1,200 per household, which will grow to $2,000 per household in 2020 and more than $3,500 in 2025.


Hydraulic fracturing is safe and well-regulated by federal and state regimes. The technologies and processes continue to be improved, guided by industry standards developed from experiences in the field and which undergo rigorous review before adoption. Here's what some say about fracking:


U.S. Interior Secretary Sally Jewell:


"Fracking as a technique has been around for decades. … I have performed the procedure myself very safely."


Former Obama Interior Department Secretary Ken Salazar:


"From my opinion and from what I've seen … I believe hydraulic fracturing is, in fact, safe. … We know that, from everything we've seen, there's not a single case where hydraulic fracturing has created an environmental problem for anyone."


Former Obama Energy Department Secretary Steven Chu (Columbus Dispatch):

Drilling for shale gas can be done safely, and at least one prominent study about the risks is not credible, said Steven Chu, until recently the U.S. secretary of energy, speaking in Columbus yesterday. The availability of natural gas from shale, including from Ohio, likely will lead to decades of low gas prices, Chu said. He also thinks the energy can be extracted in an environmentally responsible way. "You can have your cake and eat it, too," he said.


Colorado Gov. John Hickenlooper, a trained geologist with first-hand knowledge of fracking:


"I was personally involved with 50 or 60 (fracked) wells. There have been tens and thousands of wells in Colorado … and we can't find anywhere in Colorado a single example of the process of fracing that has polluted groundwater."

Finally, with another nod to fracking, increased use of natural gas has helped lower U.S. energy-related emissions of carbon dioxide to their lowest level in two decades, according to EIA.


So, add it all up – energy, energy security, economic growth, job creation, per-household savings, a cleaner environment – and there's a lot to celebrate as commercial hydraulic fracturing turns 65. While birthday celebrations traditionally include giving gifts to the one having the birthday, in the case of fracking the presents are all ours.


ABOUT THE AUTHOR


Mark Green joins API after spending 16 years as national editorial writer in the Washington Bureau of The Oklahoman newspaper. In all, he has been a reporter and editor for more than 30 years, including six years as sports editor at The Washington Times. He lives in Occoquan, Virginia, with his wife Pamela. Mark graduated from the University of Oklahoma with a degree in journalism and earned a masters in journalism and public affairs at American University. He's currently working on a masters in history at George Mason University, where he also teaches as an adjunct professor in the Communication Department.



 

Friday, March 14, 2014

Fracturing Fluid Management

Fluid Storage – "Pits" 

From the time the first oil and gas wells were drilled, "pits" have been used to hold drilling fluids and wastes.  Pits can be excavated holes in the ground, or they can be above ground containment systems such as steel tanks. Pits are used for storage of produced water, for emergency overflow, temporary storage of oil, burn off of waste oil, and for temporary storage of the fluids used to complete and treat the well. 
  
The containment of fluids within a pit is the most critical element in the prevention of contamination of shallow ground water.  The failure of a tank, pit liner, or the line carrying fluid ("flowline")  can result in a release of contaminated materials directly into surface water and shallow ground water. Environmental clean-up of these accidentally released materials can be a costly and time consuming process. Therefore, prevention of releases is vitally important. 

For pits constructed from ground excavation, pit lining may be necessary to prevent infiltration of fluids into the subsurface of the ground, depending upon the fluids being placed in the pit, the duration of the storage and the soil conditions. Typically, pit liners are constructed of compacted clay or synthetic materials like polyethylene or treated fabric that can be joined using special equipment. 

Depending on the state, there are a number of other rules regarding pits and the protection of surface and ground water. In addition to liners, some states also require pits used for long term storage of fluids to be placed a minimum distance from surface water to minimize the chances of  surface water contamination should there be an accidental discharge from the pits.  In California, for example, pits may not be placed in areas considered "natural drainage channels".  Some states also explicitly either prohibit or restrict the use of pits that intersect the water table.  

New systems have been developed that avoid the use of pits.  One technology that is becoming more common is closed loop fluid handling systems.  These systems avoid the use of pits by keeping fluids within a series of pipes and tanks throughout the entire fluid storage process.  Since fluid is never placed into contact with the ground, the likelihood of groundwater contamination is minimized.    

Fluid Handling and Disposition

Following hydraulic fracturing, fluids returned to the surface within a specified length of time are referred to as flowback.  Flowback can be comprised of as little as  3% and as much as 80% or more of the total amount of water and other material used to fracture the well.  Besides the original fluid used for fracturing, flowback can also contain fluids and minerals that were in the fractured formation. Obviously, flowback water should be managed in a responsible manner.   

The responsibility for regulating wastes such as flowback fluid lies with one or more state regulatory agencies, depending on the state.  In at least 9 states, the jurisdiction over waste management for oil and gas exploration and production activity involves more than one agency. 

Proper disposal of flowback fluids is critically important to the protection of both surface and ground water.   The vast majority of flowback fluids are disposed of in underground injection wells.  Injection of flowback fluids is conducted in a Class II injection well ‡. Underground injection of flowback is regulated by either the U.S. Environmental Protection Agency's (EPA) Underground Injection Control (UIC) program or by a state granted primary UIC enforcement authority by the EPA. At present there are 39 states, 2 tribes and 3 territories that have delegated authority from the EPA for the Class II (oil and gas related) injection well program.  The remaining Class II UIC programs are managed by EPA regional offices. 

While proper disposal of flowback fluids into permitted and monitored injection wells is currently the most effective means of safely isolating these fluids from the near-surface environment, the required specific geological conditions that are required for such wells do not exist in all areas.  Depending upon where these areas are located, there may be other methods of handling flowback fluids such as treatment and discharge.  Treatment of flowback can be conducted on-site or in centralized treatment facilities. If discharge is allowed under state or federal law, it must be done under strict controls which would typically require the issuance of a National Pollutant Discharge Elimination System (NPDES) ‡ permit from a state or the federal environmental protection agency. 

Fluid Recycling

Advances in flowback fluid treatment technology offer the promise of  using flowback fluid for other purposes, rather than simply disposing of it. The use of filtration, reverse osmosis, decomposition in constructed wetlands, ion exchange and other technologies may eventually result in the widespread practice of using flowback fluids for such things as managed irrigation and land application. One practice in use today is the recycling of flowback fluids for their reuse in other hydraulic fracturing jobs, which saves water. This technology is being used by companies like Devon Energy in the Barnett shale area around Ft. Worth, Texas. Several companies also use this technology in the Marcellus shale play in Pennsylvania.  

The chart below shows the typical flowback water handling options used in various shale gas regions throughout the U.S.

From Modern Shale Gas Development in the United States: A Primer

Hydraulic Fracturing: The Process

What Is Hydraulic Fracturing?

Contrary to many media reports, hydraulic fracturing is not a "drilling process."  Hydraulic fracturing is used after the drilled hole is completed. Put simply, hydraulic fracturing is the use of fluid and material to create or restore small fractures in a formation in order to stimulate production from new and existing oil and gas wells. This creates paths that increase the rate at which fluids can be produced from the reservoir formations, in some cases by many hundreds of percent.

The process includes steps to protect water supplies. To ensure that neither the fluid that will eventually be pumped through the well, nor the oil or gas that will eventually be collected, enters the water supply, steel surface or intermediate casings are inserted into the well to depths of between 1,000 and 4,000 feet. The space between these casing "strings" and the drilled hole (wellbore), called the annulus, is filled with cement. Once the cement has set, then the drilling continues from the bottom of the surface or intermediate cemented steel casing to the next depth. This process is repeated, using smaller steel casing each time, until the oil and gas-bearing reservoir is reached (generally 6,000 to 10,000 ft).  The diagram shown below is a generalization of a typical Eagle Ford Shale gas well in south central Texas. A more detailed look at casing and its role in groundwater protection is available HERE.



With these and other precautions taken, high volumes of fracturing fluids are pumped deep into the well at pressures sufficient to create or restore the small fractures in the reservoir rock needed to make production possible. 

What's in Hydraulic Fracturing Fluid?

Water and sand make up 98 to 99.5 percent of the fluid used in hydraulic fracturing. In addition, chemical additives are used. The exact formulation varies depending on the well.  To view a chart of the chemicals most commonly used in hydraulic fracturing and for a more detailed discussion of this question, click HERE.  

Why is Hydraulic Fracturing Used?

Experts believe 60 to 80 percent of all wells drilled in the United States in the next ten years will require hydraulic fracturing to remain operating. Fracturing allows for extended production in older oil and natural gas fields.  It also allows for the recovery of oil and natural gas from formations that geologists once believed were impossible to produce, such as tight shale formations in the areas shown on the map below.  Hydraulic fracturing is also used to extend the life of older wells in mature oil and gas fields.

How is Hydraulic Fracturing Done?*

The placement of hydraulic fracturing treatments underground is sequenced to meet the particular needs of the formation. The sequence noted below from a Marcellus Shale in Pennsylvania is just one example.  Each oil and gas zone is different and requires a hydraulic fracturing design tailored to the particular conditions of the formation.  Therefore, while the process remains essentially the same, the sequence may change depending upon unique local conditions.  It is important to note that not all of the additives are used in every hydraulically fractured well; the exact "blend" and proportions of additives will vary based on the site-specific depth, thickness and other characteristics of the target formation. 

1. An acid stage, consisting of several thousand gallons of water mixed with a dilute acid such as hydrochloric or muriatic acid: This serves to clear cement debris in the wellbore and provide an open conduit for other frac fluids by dissolving carbonate minerals and opening fractures near the wellbore. 

2. A pad stage, consisting of approximately 100,000 gallons of slickwater without proppant material: The slickwater pad stage fills the wellbore with the slickwater solution (described below), opens the formation and helps to facilitate the flow and placement of proppant material.

3. A prop sequence stage, which may consist of several substages of water combined with proppant material (consisting of a fine mesh sand or ceramic material, intended to keep open, or "prop" the fractures created and/or enhanced during the fracturing operation after the pressure is reduced): This stage may collectively use several hundred thousand gallons of water. Proppant material may vary from a finer particle size to a coarser particle size throughout this sequence.

4. A flushing stage, consisting of a volume of fresh water sufficient to flush the excess proppant from the wellbore.

Other additives commonly used in the fracturing solution employed in Marcellus wells include:

• A dilute acid solution, as described in the first stage, used during the initial fracturing sequence. This cleans out cement and debris around the perforations to facilitate the subsequent slickwater solutions employed in fracturing the formation.

• A biocide or disinfectant, used to prevent the growth of bacteria in the well that may interfere with the fracturingoperation: Biocides typically consist of bromine-based solutions or glutaraldehyde.

• A scale inhibitor, such as ethylene glycol, used to control the precipitation of certain carbonate and sulfate minerals

• Iron control/stabilizing agents such as citric acid or hydrochloric acid, used to inhibit precipitation of iron compounds by keeping them in a soluble form

• Friction reducing agents, also described above, such as potassium chloride or polyacrylamide-based compounds, used to reduce tubular friction and subsequently reduce the pressure needed to pump fluid into the wellbore: The additives may reduce tubular friction by 50 to 60%. These friction-reducing compounds represent the "slickwater" component of the fracing solution.

• Corrosion inhibitors, such as N,n-dimethyl formamide, and oxygen scavengers, such as ammonium bisulfite, are used to prevent degradation of the steel well casing.

• Gelling agents, such as guar gum, may be used in small amounts to thicken the water-based solution to help transport the proppant material.

• Occasionally, a cross-linking agent will be used to enhance the characteristics and ability of the gelling agent to transport the proppant material. These compounds may contain boric acid or ethylene glycol. When cross-linking additives are added, a breaker solution is commonly added later in the frac stage to cause the enhanced gelling agent to break down into a simpler fluid so it can be readily removed from the wellbore without carrying back the sand/ proppant material.

Fractures: Their orientation and length

Certain predictable characteristics or physical properties regarding the path of least resistance have been recognized since hydraulic fracturing was first conducted in the oilfield in 1947.  These properties are discussed below:

Fracture orientation

Hydraulic fractures are formed in the direction perpendicular to the least stress. Based on experience, horizontal fractures will occur at depths less than approximately 2000 ft. because the Earth's overburden at these depths provides the least principal stress.  If pressure is applied to the center of a formation under these relatively shallow conditions,  the fracture is most likely to occur in the horizontal plane, because it will be easier to part the rock in this direction than in any other.  In general, therefore, these fractures are parallel to the bedding plane of the formation.

As depth increases beyond approximately 2000 ft., overburden stress increases by approximately 1 psi/ft., making the overburden stress the dominant stress This means the horizontal confining stress is now the least principal stress.  Since hydraulically induced fractures are formed in the direction perpendicular to the least stress, the resulting fracture at depths greater than  approximately 2000 ft.  will be oriented in the vertical direction.

In the case where a fracture might cross over a boundary where the principal stress direction changes, the fracture would attempt to reorient itself perpendicular to the direction of least stress.  Therefore, if a fracture propagated from deeper to shallower formations it would reorient itself from a vertical to a horizontal pathway and spread sideways along the bedding planes of the rock strata. 

Fracture length/ height

The extent that a created fracture will propagate is controlled by the upper confining zone or formation, and the volume, rate, and pressure of the fluid that is pumped. The confining zone will limit the vertical growth of a fracture because it either possesses sufficient strength or elasticity to contain the pressure of the injected fluids or an insufficient volume of fluid has been pumped..   This is important because the greater the distance between the fractured formation and the USDW, the more likely it will be that multiple formations possessing the qualities necessary to impede the fracture will occur.  However, while it should be noted that the length of a fracture can also be influenced by natural fractures or faults as shown in a study that included microseismic analysis of fracture jobs conducted on three wells in Texas, natural attenuation of the fracture will occur over relatively short distances due to the limited volume of fluid being pumped and dispersion of the pumping pressure regardless of intersecting migratory pathways.

The following text and graphs are excerpts from an article written by Kevin Fisher of Pinnacle, a Halliburton Company for the July 2010 edition of the American Oil and Gas Reporter.

"The concerns around groundwater contamination raised by Congress are primarily centered on one fundamental question: Are the created fractures contained within the target formation so that they do not contact underground sources of drinking water? In response to that key concern, this article presents the first look at actual field data based on direct measurements acquired while fracture mapping more than 15,000 frac jobs during the past decade.

Extensive mapping of hydraulic fracture geometry has been performed in unconventional North American shale reservoirs since 2001. The microseismic and tiltmeter technologies used to monitor the treatments are well established, and are also widely used for nonoil field (sic) applications such as earthquake monitoring, volcano monitoring, civil engineering applications, carbon capture and waste disposal. Figures 1 and 2 are plots of data collected on thousands of hydraulic fracturing treatments in the Barnett Shale in the Fort Worth Basin in Texas and in the Marcellus Shale in the Appalachian Basin.

Figure 1.  Barnett Shale

More fracs have been mapped in the Barnett than any other reservoir. The graph illustrates the fracture top and bottom for all mapped treatments performed in the Barnett since 2001. The depths are in true vertical depth. Perforation depths are illustrated by the red-colored band for each stage, with the mapped fracture tops and bottoms illustrated by colored curves corresponding to the counties where they took place.

The deepest water wells in each of the counties where Barnett Shale fracs have been mapped, according to United States Geological Survey (http://nwis.waterdata.usgs.gov/nwis ‡), are illustrated by the dark blue shaded bars at the top of Figure 1. As can be seen, the largest directly measured upward growth of all of these mapped fractures still places the fracture tops several thousands of feet below the deepest known aquifer level in each county.

Figure 2 Marcellus Shale

The Marcellus data show a similarly large distance between the top of the tallest frac and the location of the deepest drinking water aquifers as reported in USGS data (dark blue shaded bars at the top of Figure 2). Because it is a newer play with fewer mapped frac stages at this point and encompasses several states, the data set is not as comprehensive as that from the Barnett. However, it is no less compelling in providing evidence of a very good physical separation between hydraulic fracture tops and water aquifers.

Almost 400 separate frac stages are shown, color coded by state. As can be seen, the fractures do grow upward quite a bit taller than in the Barnett, but the shallowest fracture tops are still ±4,500 feet, almost one mile below the surface and thousands of feet below the aquifers in those counties.

The results from our extensive fracture mapping database show that hydraulic fractures are better confined vertically (and are also longer and narrower) than conventional wisdom or models predict. Even in areas with the largest measured vertical fracture growth, such as the Marcellus, the tops of the hydraulic fractures are still thousands of feet below the deepest aquifers suitable for drinking water. The data from these two shale reservoirs clearly show the huge distances separating the fracs from the nearest aquifers at their closest points of approach, conclusively demonstrating that hydraulic fractures are not growing into groundwater supplies, and therefore, cannot contaminate them."

 

* Pennsylvania Department of Environmental Protection
"Hydraulic Fracturing Overview." 07/20/2010. 

Thursday, March 13, 2014

Industry aims to unlock mysteries of fracturing downhole

Whether it is sliding sleeves vs. PNP or slick water vs. crosslinked gel, proponents of fracturing technology are passionate about their preferences.

US net crude oil imports are dropping and will continue to drop even more. The idea of achieving US energy security will get stronger over the years, and it is being driven by hydraulic fracturing, shale gas, and tight oil, said John Martin, founder of JP Martin Energy Strategy LLC.

The number of drilling rigs, frac crews, and other infrastructure doesn't exist elsewhere in the world. The shale revolution won't happen tomorrow, but it will happen, Martin emphasized in a "Hydraulic Fracturing 101" webinar produced by Energy Seminars International in January.

"The technology investment in hydraulic fracturing and horizontal wells is paying off," he said. "It is amazing to watch the transformation of the industry where it is getting into these tight rocks and producing that hydrocarbon at a cost that looks like the 1970s."

In some ways, the technology of hydraulic fracturing is just beginning. The industry is moving from using brute force along the length of a lateral to finding ways to finesse the oil and gas out of the formations with optimum placement of stages and clusters.

"I would say that the efficiency successes and the cost efficiencies that we've seen on the drilling side are lagging somewhat on the completion side of our business," said Rob Fulks, director of shale resource projects and pressure pumping services for Weatherford. "There is so much pressure on operators to reduce their completion costs, which seems to be paramount right now. The drilling side has done such a great job in getting the days to depth reduced that it's hard to keep up with the efficiencies on the completion side that they're seeing on the drilling side."

Jeff Meisenhelder, vice president, unconventional resources, Schlumberger, noted that the recovery factor for the liquid phase is about 8% to 12%. "It would be a giant step-change in the industry if we doubled the recovery factor. If a good well in the Eagle Ford produces 500,000 bbl estimated ultimate recovery (EUR), then a well that produces 1 MMbbl EUR would be a new game economically." Some of these game changers can be found in unlikely places, according to John Ely, founder of Ely and Associates.

"We're having a lot of success not only in source rock shales and stacked sand-shale sequences but also in carbonate reservoirs across the country, which are extremely tight formations that the industry has overlooked," Ely said. "We're making 150 b/d to 300 b/d wells. These are vertical wells with very large slickwater fractures down 7-in. casing, which makes it easy to pump.

"One of the interesting things is that some of the operators are finding that vertical wells with proper frac designs are more economical than horizontals. At the same time we are also achieving extraordinary results with all types of fractured reservoirs using fracture location technology to bypass the statistical lateral stage length and number-of-clusters guessing game, which dominate our industry," he added.

Statoil US onshore is out to create the "perfect well" in drilling, followed by completions (including hydraulic fracturing), rig moves, and completion operations. The perfect well will always be another step-change beyond best demonstrated performance (BDP), explained Kevin O'Donnell, head of operations support for Statoil US onshore.

"BDP has a basis of reality," he said. "It has been accomplished in the field. We have seen cases where what we thought was perfect turned out two years later to be less than what we thought was perfect."

As Martin noted, drilling costs and completion times are dropping. Initial production (IP) and EURs are better. "This is what is going to cause a global revolution," he said. "It has certainly caused a North American revolution."

But how much farther can the oil industry go in improving hydraulic fracturing, completion efficiency, and production effectiveness? E&P interviewed experts in the field about what direction they see the industry and technology heading.

Well productivity

How do companies go about increasing well productivity? "There are several trends that we're noticing," Fulks said. "I guess one of the bigger ones is led by Laredo, UG, Continental Resources, and some other companies. There's a tendency toward super fracs. UG in particular has shown that by increasing proppant loading, well IP rates can be vastly affected positively."

As an example, Fulks said Weatherford has a client that consistently stimulates 3,049-m (10,000-ft) laterals with 32 stages in the Bakken. That company is completing those 32 stages with a total of 2.4 MM lbs of proppant. In the same area, EOG is using 7.4 MM lbs to 10 MM lbs and in some cases north of 12 MM lbs of proppant in the same type well, and its IP rates are dramatically different.

Ely said his company is watching very closely recent high-water volume, high-sand volume treatments with slick water, where the only proppant utilized was 100 mesh and 200 mesh sand. These types of treatments have been conducted in oil-producing reservoirs at depths greater than 2,439 m (8,000 ft) and as deep as 4,651 m (12,000 ft).

"The wells are performing quite well. Two things are unique for this type of treatment. The first is extremely high volume of fluid, and second is the exclusive use of

small proppant in oil reservoirs. The industry or the majority of the industry has seen and accepted small proppant in gas reservoirs but has proclaimed the need for bigger sand for oil. That is simply not the case for the low-matrix permeability reservoir where complex fractures are created."

All the things the industry was taught in fracturing conventional wells – using crosslinked gel, packing the fracture with sand, and pounds per square foot – don't work in naturally fractured reservoirs, he explained. Legendary oil man George Mitchell proved that what is needed is high-rate, high-volume slick water.

The industry is now pumping a lot of non-American Petroleum Institute sand.

"We didn't have the volumes to pump all Ottawa sand or all ceramics in our early frac treatments in the deeper shales," Ely said. "What we've found – not out of science but experience – is that smaller sands work in deep shales like the Eagle Ford and Haynesville. One of the biggest operators in the Haynesville hasn't pumped anything but small sand for the last three or four years, and that is at 3,658 m (12,000 ft).

"Truly the enhanced productivity is due to massive surface area. You can get much larger volumetrics with just water, friction reducer, and small proppant. The small proppant is transported farther, and it is smaller and able to penetrate into smaller fractures," he emphasized. He pointed to a 600-well study in the Eagle Ford that showed volume of fluid, not sand, was the No. 1 factor in hydrocarbon recovery. It may be that both volume and sand are needed, he said. With the emphasis on smaller sand for slickwater fracs, operators are faced with having enough proppant on location, Fulks said. "When we talk about increased proppant loading, we're seeing demand for proppant way, way greater. That means usage is going up tremendously, just as we thought," he said. "Having onsite storage sand, particularly if you're going to do zippers or multiple wells on a pad, is extremely important to cut down on the truck traffic." Meisenhelder stated, "Arranging perforating clusters into stages with similar initiation pressures has proven very effective in improving IP and making every fracture count, but you need data along the lateral to make it possible. New

tools and conveyance technologies have brought the cost and risk of gaining this data down to an acceptable level. This technique is rapidly gaining acceptance."

Following natural fractures

Getting results from natural fracturing is very basic, according to Ely.

"What works is surface area and volumes," he said. "Not many things are cheaper than water. Efficiency when you switch over to something like nitrogen or carbon dioxide goes down even in these very tight reservoirs, and the cost goes up."

There are, however, plenty of applications where nitrogen and carbon dioxide are needed due to logistics with water supply or extreme underpressure.

Typically these are reservoirs with naturally fractured, low-permeability rocks.

"If you're talking about low-permeability rock, the only thing that is going to work is surface area that is propped open and has conductive flow paths," Ely explained. "With slick water, we're getting very complex, spider-web type fracture systems, and we're making better wells with smaller sand. That's the big step-change in our industry."

One way to see what is happening in the reservoir is to use formation microimaging logs. "If you can do that, then you can cheat and actually perforate into the fracture systems," he added. "Then we'll quit guessing and experimenting with the number of clusters and actually perforate where we should."

One problem with microimaging logs is that the technology is not compatible with oil-based mud and a lot of the shale is drilled with that type of mud.

"The oil-based technology is not such that we can selectively perforate the brittle zone," Ely said. "There are service companies promising that they can get microimaging logs with oil-based mud that will allow us to quantify fracture presence. An oil-based microimaging system that can be run in LWD would be a tremendous boost in our ability to effectively stimulate naturally fractured reservoirs."

Microimaging systems work very well in water-based drilling muds. "That technology has been extensively used but not widely advertised," Ely said. "Lateral microimaging greatly enhanced the development of the northern Barnett shale."

Slick water vs. crosslinked gels

With the added volume of proppant in the fractures, the debate over which fluid is best for placement – either slick water or crosslinked gels – continues unabated.

"It's a very interesting time in our industry where we're just about as bad as the Democrats and Republicans. We've got the slickwater people and the gel people. I think we know who is winning," Ely said as he laughed. "About 80% of the jobs, probably higher, are in fact slick water."

Conversely, Meisenhelder indicates that statistics show hybrid jobs, where fracs are initiated with slick water but

followed by cross-linked gel, are increasing, while the overall use of slick water is decreasing. The hybrid technique takes advantage of the properties of slick water but also capitalizes on the better proppant transport capabilities of gels. "Advanced fracture modeling tools that take into account both rock properties and fabric are enabling us to predict the effects of changing fluid designs on fracture complexity, proppant distribution, and conductivity. We can now efficiently optimize job designs that are fit for the reservoir you have rather than the one next door."

Ely thinks hybrid fracs are slick water fracs. "I think what's confusing people is that the majority of jobs that are crosslinked have no stability and are basically water after a short period of time," he said. As a hydraulic fracturing consultant, his company did 27,000 frac stages in 2012.

"What we believe is that the thin fluids in high-volume water fracs are giving complex fractures, and that's why we're having so much success in the shales," he said.

But Ely also recognizes the need for gels. "We can testify that in the Haynesville if you don't run viscous fluid, you can't place sand due to severe tortuosity, and that gets complicated," he said. "But once you remove tortuosity in a lateral you can pump anything you want to. What we're finding is that we get better results with smaller proppant, which is counterintuitive for fracturing. We're finding across the country and the world that slick water is working virtually everywhere.

"For anything that is naturally fractured, whether it is shale or coal or carbonates in West Texas, what's really working is slick water, and it's the primary reason for the ongoing gas bubble and our huge increase in oil productivity," he added. "Many of the larger operators in Eagle Ford have switched from hybrids back to slick water."

Statoil's 'perfect well'

Statoil has some deliberate improvement initiatives. Rather than evolving over time – a learning curve – the company has initiatives to accelerate the learning curve in this phase of its evolution, which is called the "perfect well."

"The perfect well is based on an old Japanese manufacturing process called SMED, which stands for single minute exchange of die," O'Donnell said. In manufacturing, a die is a device used to shape, finish, or impress an object. "It's a very simple process for breaking down what you do in a lot of detail, questioning why and how you do it, and building back up from the bottom and getting a different and better result."

The process begins with understanding what is being done today in detail. Next, there is a discussion around the table about what can be eliminated. Statoil began with its drilling operations and will progress later into completions. The ideal group to discuss processes consists of about a dozen people intimately familiar with the operation – drilling engineers, engineering supervisors, drilling managers, and superintendents along with the drilling contractor on the rig. Over a three-day period in August 2013, Statoil facilitated the workshop, asking what can be eliminated.

"What we find out from our teams is that what we thought are requirements really aren't and that we can actually take them out of the process to get the same or better results by eliminating certain steps," he explained.

The group then looks for steps that can be moved off the critical path. "In the case of a drilling operation that runs about [US] $100,000 a day, anything that we can take off the critical path and do before, parallel, or after will take that cost away, which will shorten our overall cycle time," he said. "Next we look at what we can shorten through technology, automation, or better processes. When we implement the changes, we've saved a whole bunch of time in our cycle time.

"If you look into literature around SMED, it has been documented in manufacturing that up to 45% can be saved with each cycle of this process," he added. "In our case, from previous history, we performed this through facilitated workshops around the world and have seen that the numbers come in around 50%."

In the Eagle Ford workshop, Statoil started with drilling. The group came up with 98 different improvement ideas. Each of those 98 ideas was evaluated about how each shows up as potential time savings. These were then turned into 98 mini-projects. Each project will be turned into reality, although some projects may not be cost-effective, which means not all projects will become reality.

"It's not just an idea, but we have a process to drive them into reality in the field, so we actually cut our cycle time," O'Donnell said. "So far, 23 of those mini-projects have been completed, and there are 75 left to do. Each time one of those is completed, in theory, we improve our operation and reduce our cycle time."

Statoil has been benchmarking its performance as an operator in the Eagle Ford. The company used Rushmore Reviews to benchmark the performance of the operators in the area, including the Norwegian company.

"Statoil was actually the most efficient at 755 ft/d [230 m/d]," he said. "If you look at the perfect well work and what we're shooting for today, our next milestone is to hit the 20-day well. That's a big milestone, which would put us somewhere near 1,000 ft/d [305 m/d]. And that doesn't change around the world for onshore very much. If you're averaging [305 m/d] in your operation, then you're at the top or near the top in efficiency in your area. Not many companies can achieve that." It remains to be seen how much efficiency can be gained in the hydraulic fracturing and completion areas for Statoil.

Trends in hydraulic fracturing

Fulks said service companies are focusing on helping clients achieve lower completion costs while at the same time increasing productivity by getting a better frac job, for example. On the side of lowering costs, the continued use of zipper fracturing is more efficient. Fuel substitution with compressed natural gas, propane, or even line gas can reduce diesel costs by up to 70% in certain cases.

"Smart scheduling is another trend," Fulks said. "It's basically service companies like ours working with our clients and saying, 'Look, we can afford to give you lower pricing if you'll help us manage our days-per-month asset utilization.' If we can be setting up on the next well while we're finishing this one, it's a more efficient use of our assets. This has been going on a long time, but it's becoming a little more formalized."

A number of years ago, there was something called frac-on-the-fly. What service companies are doing now is real-time monitoring of frac jobs during the fracturing.

"We're actually estimating the stimulated reservoir volume or stimulated rock volume by stage as we're going along," Fulks said. This is useful, for example, if an operator wants to determine whether sliding sleeves or plug and perf (PNP) would drain the best and be more productive without having to wait two years for production data. "How can we figure it out faster? You can actually figure it out fairly quickly right away," Fulks said. "Let's say you have a 10-stage well; you run five stages in the bottom as PNP and the other stages as sliding sleeve because most sliding sleeves now will work in a cemented application as well. You simply compare the stimulated rock volume or the estimated stimulated volume for each one of those.

"You can immediately see the impact through microseismic of what you think is happening to your formation downhole. Now microseismic is still qualitative more than quantitative, but it's a very quick look at what's going on downhole, and that's kind of interesting," he added. "Lastly, we think we can safely say that we see a trend back toward slickwater fracs and perhaps away from the more complex fluids. It's not in every play but in quite a few plays."

Fulks said that stacked lateral wellbores are another big trend that's happening, particularly in the Permian and the Bakken.

"That is where you see multiple wells in basically the same service acreage and are simply doing more effective drainage of the given acreage position," Fulks said. "You're going to see multiple stacked pays in the Bakken and the Permian. One company that has some interesting diagrams out there right now is Laredo."

Using data to improve efficiency, effectiveness

There are two areas that can address some of the challenges around fracturing – material sciences and computing power, according to Meisenhelder.

An example of gains through material science is the ELEMENTAL degradable alloy technology that degrades completely and predictably in a wide range of downhole conditions without the need for chemical additives. Components of the completion made of these materials will degrade on their own, eliminating steps in the completion and cleanout process.

Meisenhelder noted that on the efficiency side the industry is looking for a step-change from new technology. "In many cases we are approaching the technical limit for drilling and completing wells with the technology we have. The next step-change in efficiency will likely come from a game-changing technology," he said.

Both Meisenhelder and Fulks pointed to the importance of computer models in improving cluster placement and effectiveness.

Increased computing horsepower can do a lot for the industry in planning clusters and stages, engineering completions, designing near-wellbore solutions, determining drainage area, and placing multiple wells and laterals, Meisenhelder explained. But the biggest single opportunity in the industry is still the low expected ultimate recovery. "How you double EUR is a big question out there, more so than cutting the cost of the well," he continued.

Fulks described a trend called completing smarter, which uses LWD logs, cuttings analysis, or gas-ratio analysis to adjust the stage and packer positioning.

"Everybody's been talking about it for a long time, but there's been some recent success in the Eagle Ford," he said. "Let's say you've got 20 stages in the Eagle Ford. You simply arrange them better whether you're using lithology, brittleness, total organic content, or some other algorithm of logging responses. We're seeing clients with results that show 20% to 24% improvement in IP rates.

"Now, does that mess up your zipper design? It could. We recently conducted a small survey asking completion engineers, 'If you could find a way to tweak your stage and cluster spacing but it gave you a 16% increase in IP rates, would you risk screwing up your zipper designs?' And every one of them said, 'Yes, we would.'"

Improving sliding sleeves

Controlling where fluids go is the critical part of hydraulic fracturing, Ely emphasized. "That is why the sliding-sleeve people are trying to develop multiple entry ports and cemented, multiple-entry sleeve systems," he said. "The biggest problem is that you are having to deal with corrosion, scaling, and fines, which occur in opening and closing the sleeves."

However, if technology can solve the problem, it would benefit restimulation efforts. The development effort is aimed at building a sliding sleeve that can be used to perform the initial stimulation and then three to four years later be used to close off the original openings and stimulate through new openings.

"If we can do that, we will add a new dimension to enhancing removal of oil and gas in place," Ely said.

Having absolute control of where the fluids go is the reason why PNP completions are dominant in the industry. About 80% of completions use this method, he said.

Industry integration, crew training

Integrating different disciplines is something the industry talks about but is a lot harder to do, Meisenhelder said. "To really integrate, you need to challenge all disciplines with a single problem."

Weatherford has worked with one major oil company that only wanted to work with a single, fully integrated company. The company told service companies that if their services didn't include coiled tubing, wireline, plugs, and flowback along with the frac, don't even bother. The company wanted to talk to a service provider that's integrated.

"That really reduced its tender list," Fulks said.

Weatherford has had great success with other companies in integrated completions. "We saw agreed-upon key performance indicators (KPIs) going up across the board, whether it was with the drilling side, the completions side, or even the artificial lift side by going to an integrated approach," Fulks explained.

"Let's say your KPI is going to be uptime. If there is any nonperformance time, nobody gets paid for it. Before, if the wireline company hit a snag and it cost six hours, the frac company still charged for standby time. However, in an integrated situation, basically it's all for one and one for all. If there is a problem, nobody gets paid standby until the problem gets fixed. And I'll tell you, that puts the onus on efficiency on the service companies. Some service companies embrace it, and those that don't won't even go near it," he said.

Crew training is just as important as it ever was. Having a competency, a career path, and training is the heart and soul of this business, Fulks said.

"We certainly implemented our own training programs and continue to bring more people in and have them go through competency training," he said.

In addition to its own training, Weatherford hired an outside consulting firm to offer additional eyes and ears on its training program. "The consultant basically runs its crews through the wringer just to see if they are field-ready to deal with onsite company

men," Fulks said. "[The consultant] has a lot of wellsite consultants basically monitoring frac jobs for operators because it's rare that an operator actually has its own personnel on location."

Decline curve problems, refracturing

The industry currently spends a huge percentage of its capital on the first two months of the well life. The emphasis is on drilling and completing the well, Meisenhelder explained, rather than on managing the well for the remaining 30 years of life. "But how we manage flowback and production could be adding to production decline in wells. Production in some wells could decline so rapidly that the operator abandons the well rather than studying the problem," he said.

Production practices can contribute to near-borehole fracture damage, fines from proppant crushing, scale, and mechanical changes in the rock – all of which steepen declines. "The technology exists to optimize the post-frac life of the well, but it comes back to having information. Without data about the reservoir or the rock you cannot explain why one well produces better than another or declines at a slower rate, nor can you identify a good refrac candidate," he added.

"Almost by definition, normally fractured formations need to be restimulated because of a generation of fines, scaling, etc.," Ely said. "The problem is that a lot of the techniques we've used are such that it is very difficult to restimulate. We're working very hard on that problem and technology that we think will allow us to restimulate.

 

 

Bar association offers new guide for dealing with hydraulic fracturing issues

By Erica Levine Powers and Beth E. Kinne, American Bar Association

The American Bar Association is offering a 350-page book on Beyond the Fracking Wars: A Guide for Lawyers, Public Officials, Planners, and Citizens. The book provides an accessible and credible reference that covers the technologies and regulatory framework governing oil and gas development via hydraulic fracturing; case studies exploring the hurdles, pitfalls, and opportunities for creative solutions; and innovative approaches to managing the impacts of the "shale gale" on both the regional and international level. Written by authorities in a wide range of fields, this book is organized into four parts: Part I: Technology and industry overview, providing a detailed overview of the technology, structure, development, and relationships with regulators; Part II: Legal issues, providing the legal foundations, federal regime, and local approaches; Part III: Nongovernmental, governmental, community and industry perspectives, offering a series of case studies providing a basic understanding and viewpoint from real people in real places; and Part IV: Getting beyond the fracing wars, focusing on some less frequently addressed issues and challenging the reader to think broadly and deeply about the implications of current legal relationships and common practices. For more information on Beyond the Fracking Wars, visit ShopABA.org

 

 

Companies customize environmentally sustainable water treatment

Increases in water consumption and subsequent disposal issues are prompting operators to look for more economic and environmentally sustainable treatment options for produced and flowback water associated with hydraulic fracturing. To aid in that effort, Baker Hughes is partnering with DuPont Chemical Solutions to provide a self-contained, chlorine-dioxide- (ClO2-) based treatment solution that both companies believe will lead to best practices for oilfield water treatment.

Baker Hughes is using custom-engineered generators from DuPont as well as its expertise in the application of ClO2 to ensure safe and efficient generation of ClO2 in its H2PrO HD service to treat hydrogen sulfide (H2S), and bacterial contamination. Baker Hughes has ruggedized the generators to withstand harsh oilfield conditions and fitted them to the company's treatment trailers.

ClO2 has been used for more than 60 years in municipal drinking water, food processing, and industrial applications. For more than a decade it has been used in refinery treatments. Today that use is expanding to hydraulic fracturing treatment; remediation of near-wellbore damage in production, injection, and disposal wells; and as a biocide for water in surface storage. Its unique chemical and biological properties are capable of quickly and efficiently removing contaminants and treating the water to support successful fracturing fluid design.

ClO2 is a selective oxidizer that works at low dosages and offers a broad range of bacteria, fungi, and virus destruction. As a gas in aqueous solution, it penetrates and sloughs biofilm, mitigating the destructive bacteria. It is nontoxic, approved by both the EPA and FDA, and does not form trihalomethanes (THMs), assimilable organic compounds (AOCs), hypochlorous acid, or free chlorine. It is less corrosive than chlorine and oxidizes manganese, iron, phenols, sulfides, cyanides, and odor-causing substances.

As part of the H2PrO HD service, ClO2 is generated onsite via a mobile or permanently mounted DuPont generator. The vacuum-based system dramatically improves safety by creating the ClO2 in the water flow rather than pumping it or using a reaction chamber. The treatment provides a powerful biocide that neutralizes bacteria, H2S, iron sulfide, phenols, mercaptans, and polymers in the water. By neutralizing these substances, the treated water can be reused with no negative impact to chemicals used in hydraulic fracturing, the producing formation, or to downhole equipment. The water management service includes pre- and post-water testing to ensure compliance with operator water quality standards.

With fast chemical reaction time, concentrated solutions, and high ClO2 generation rates, the service can treat up to 600,000 bbl of water per day with a single unit. The mobile generator system can be set up very quickly – often in just one hour.

In 2013, more than 40 million barrels of water and 600 wells were treated with the H2prO HD service in hydraulic fracturing operations in the Permian basin, South Texas, the US Rocky Mountains, and Northeastern US shale plays.



Scott Weeden, Senior Editor, Drilling, Hart's E&P Magazine, 

Curable resin-coated proppant prevents proppant flowback

The right curable resin-coated proppant can maximize a well's performance and net present value.

Proppant flowback, whether raw frac sand or resin-coated sand, can occur immediately with fluid flow-back at the time of pressure release or throughout the well life during hydrocarbon production. This is an undesirable condition for two primary reasons: The interruption of hydrocarbon flow decreases revenue in the short term, and potential equipment damage increases intervention cost.

Intervention cost to repair damage to tubulars, wellhead assemblies, and valves, for example, can be quite costly, according to two operators' data reviewed by Santrol. The data sources are a 3,048-m (10,000-ft) vertical pumping well and a 4,878-m (16,000-ft) measured depth horizontal well producing from the same formation in South Texas. Typical intervention service averages US $65,000 for the vertical well and $100,000 for the horizontal well.

The significance of frac sand flowback has been documented by operators. Pope et al.examined this situation in south Texas. In the Big Wells field in Dimmit and Zavala counties, an operator compared the failure rates of 31 wells fractured with 100% sand and 31 wells fractured with a resin-coated tail-in. The vertical wells were rod-pumped at an average depth of 1,646 m (5,400 ft). The resin-coated sand tail-in wells had a 0.19 failure frequency rate per well annually compared with a 1.25 annual failure rate for the 100% sand wells. Downhole failures were stuck pump plungers, eroded pump valves, sucker rod failures, stuck tubing, and sand fill.

As far as hydrocarbon production goes, proppant that flows back reduces the proppant volume in the fracture and can significantly reduce production. In the long term, reduced conductivity can cause the fracture to close, disconnecting the hydrocarbon flow path and production.

curable resin-coated sand

FIGURE 1. Bonded curable resin-coated sand was tested at 1,000 psi closure stress for 24 hours at 121°C. (Image courtesy of Santrol)

 

This situation negates the purpose of the fracturing process and causes a loss of some or all of the fracturing investment. In the worst-case scenario, the well may have to be refractured.

Flowback control

Resin-coated proppant was developed in 1976. Curable resin-coated proppant remains the industry standard to prevent flowback. Curable resin-coated proppant can be included with the fracturing fluid at 100% or as tail-in in the range of 15% to 30% of the total proppant amount.

Curable resin-coated proppant in the presence of pressure, temperature, and moisture is pressed together. The resin that is coated onto the proppant begins to cure and bond, forming a proppant pack. Neither sand nor ceramic proppant alone can prevent proppant flowback because these elements cannot bond (Table 1).

After shut-in, the pumping company flows back the hydraulic fracturing fluid. Because the individual curable resin-coated proppant particles have bonded to each other, these particles are unable to flow back into the well-bore. The pumping company working on behalf of the operator has prevented proppant flowback and the damaging effects of that condition.

proppant flowback recommendations

TABLE 1. Proppant flowback recommendations are shown for low, moderate, and high closure stress conditions.

 

Proppant manufacturing

Resin-coating uniformity coupled with engineered resin-curing characteristics that fit a desired curing profile are critical to proppant performance, specifically strength, conductivity, and flowback control. A reputable proppant manufacturer adopts highly optimized processes and strict quality control procedures for raw materials to create a better resin-coated proppant.

With good manufacturing processes, the curable resin builds bond strength quickly, enabling a short shut-in time. The proppant pack bond strength is maintained during the well life.

All of these steps are designed for an operator to achieve maximized flowback control to ensure optimal conductivity for increased hydrocarbon production and well net present value. As the final quality control step, a reputable proppant company frequently applies two tests to determine prop-pant flowback performance – the unconfined compressive strength (UCS) test and the proppant flowback test.

Flowback testing

A typical UCS test subjects the proppant pack to 1,000 psi closure stress at 121°C (250°F), based generally on well shut-in time after six hours, 12 hours, 18 hours, and 24 hours. The proppant particles set and bond into a disk-shape specimen. The specimen's UCS value is a measure of the proppant's bond strength (Figure 1). The associated bond strength of the proppant pack is reported in psi.

The proppant flowback test can be performed at temperatures up to 204°C (400°F) and closure stress up to 12,000 psi with stress-cycling options. The cell rig can be used to simulate liquid, gas, or multiphase flow. A laboratory technician can measure the amount of proppant grains dislodged from the pack, another measure of the proppant's bond strength.

If there is low proppant grain dislodging in the flowback test, coupled with an adequate UCS value, an operator can be confident the curable resin-coated prop-pant will offer superior proppant flow-back prevention.

Choosing the best proppant

In certain formations, proppant flow-back control is critical to producing a better well. Flowback control depends on choosing the right curable, which is based on resin-coating uniformity and engineered characteristics verified by rigorous testing. A reputable proppant manufacturer follows these guidelines to ensure a superior product that prevents the potential cost exposure caused by flowback, equipment damage, and refracturing.


Ramanan Pitchumani, Kanth Josyula, Scott Greenbauer, and Taso Melisaris, Santrol

Fluids maintain wellbore integrity in technically challenging wells

Flat-rheology invert emulsion drilling fluids have made strides in maintaining a fluid that is resistant to sag.

When flat-rheology drilling fluids were introduced a decade ago, they brought the promise of reduced drilling equivalent circulating densities (ECDs), break circulation pressures, and surge pressures while tripping and running casing. Primarily intended for drilling narrow pressure windows in deepwater environments, these benefits spanned into other critical well conditions such as extended-reach drilling and HP/HT drilling.

However, these drilling fluid systems have fallen short of their promises in some cases. Furthermore, questions have been raised with regard to maintaining the highest level of wellbore integrity when using these drilling fluid systems.

Improving flat-rheology systems

Flat rheology as it relates to drilling fluids generally refers to the characteristics of a particular fluid to demonstrate a minimal variance in a few key rheological properties across a wide temperature range. Those properties that relate most directly to annular hydraulics are used to define whether a fluid is "flat" or not. In most cases, these properties are the 6-rpm viscometer reading, the 10-minute gel strength, and to a lesser degree the yield point or low-shear yield point.

flat-rheology invert emulsion

FIGURE 1. This figure represents the typical approach to flat-rheology invert emulsion systems. (Images courtesy of M-I SWACO)

 

The American Petroleum Institute (API) standard of measuring the rheology of oil-based drilling fluids at 66°C (150°F) has been expanded for evaluation of flat-rheology systems. Commonly, the rheology is also measured at two additional temperatures. For most deepwater wells, the typical temperatures are 4.5°C (40°F), 38°C (100°F), and API standard 66°C.

An additional measure to flat-rheology fluid systems is the evaluation of the gel strength progression over time. The inclusion of measured 30-minute gel strengths has added breadth to the API standard 10-second/10-minute test regime. The ratio of gel strength progression across the time interval indicates the degree to which break-circulation pressure and surge/swab effects will continue to increase following extended static periods. Due to the wide shift in temperature on deepwater wells, this effect can be exaggerated.

Using organophilic clay as viscosifier

With conventional invert emulsion drilling fluids, the use of organophilic clay as a viscosifier results in rheological properties that change greatly with the circulating temperature. This results in a drilling fluid that is thinner near the bit and becomes more viscous as it cools while traveling up the annulus to the flowline. During extended periods of drilling or circulating, a system will find a level of equilibrium that is greatly defined by the temperature gradient of a given drilling environment. Land-based or shallow-water offshore wells often exhibit flowline temperatures elevated significantly above ambient surface temperature.

However, in deepwater wells the cold temperature often associated with the surrounding sea conditions, coupled with the reduced annular velocity in the riser, cool the drilling fluid significantly. As a result, flowline temperatures are frequently below ambient surface conditions.

During extended static periods such as bit trips, casing operations, and operational upsets due to inclement weather, the drilling fluid in the hole equalizes to the surrounding environment. Thus, the observed temperature range for the fluid in the hole can range from less than 4.5°C to more than 177°C (350°F). The apparent viscosity of a conventional invert emulsion drilling fluid will also have a dramatic range. Gel strengths in a conventional system can be 200% to 300% greater at cold temperatures compared to the same fluid at a higher temperature.

drilling fluids data

FIGURE 2. Real-time processing of automated drilling fluids data with hydraulics simulations is shown here.

 

Due to this natural tendency, the typical approach to designing flat-rheology systems has been to reduce or eliminate organophilic clay in an effort to minimize cold temperature gelation (Figure 1). A polymeric viscosifier is added that becomes more active as the temperature increases. The combination of these two results in a fluid system that compensates for the normal viscosity shift at varied temperatures.

Addressing barite sag

This approach has led to some undesirable consequences. Most notable – and experienced throughout the industry – is the occurrence of barite sag that has become more frequent with the increased use of flat-rheology systems. The implications of barite sag extend into both dynamic and static conditions. While drilling, imbalances in circulating pressures can occur, and equivalent downhole densities fluctuate.

On wells with critical limits between pore pressure and fracture gradient, these small fluctuations can make the difference between inducing fractures and staying within the narrow operating window. Under static conditions, there is an ever-present risk of a well control event if a drilling fluid cannot resist a change in density. Varied mitigations have been made to compensate for this deficiency.

In some cases, nonorganophilic clays have been used in an effort to supplement the gel strengths provided previously by organophilic clay. However, a common practice throughout the drilling fluids industry has been to engineer flat but thick fluid systems. By doing so, the original intended benefits of improved control over lost circulation, the ability to drill within narrower margins, and improved tripping speeds have been marginalized.

By design, M-I SWACO has approached flat-rheology invert emulsion systems with the intention of keeping organophilic clay in the formulation. This requires manipulation of the normal organophilic clay chemistry. The RHELIANT Plus flat-rheology drilling fluid system, which is a second-generation flat-rheology system, has made strides in improving the balance between maintaining a fluid that is resistant to dynamic or static sag while at the same time reclaiming the original intended benefits of flat-rheology systems. One of the key improvements with the second-generation system is evident with the ability to increase the organophilic clay content by approximately 50% compared to previous-generation systems. Despite the increase in organophilic clay, gel strength progression has been notably reduced. Table 1 compares the gel strength progression of a typical conventional invert emulsion system to similarly specified flat-rheology systems.

The primary emulsifier and rheological modifier in the second-generation system work along with organophilic clay to deliver the flat-rheology profile. The emulsifier reduces organophilic clay gelation at low temperature and limits the progression of gel strength over time. The rheological modifier offsets the natural tendency of the organophilic clay to lose activity and become thinner at higher temperatures.

By doing this, a robust concentration of organophilic clay can be included in the fluid formulation that provides excellent suspension of weighting materials and cuttings, resilience against sag, and thermal stability of the fluid

under extended static periods exposed to downhole temperatures. Historically, the concentrations of organophilic clay required to provide these benefits would come with the undesirable effect of high gel strength progression.

mineral oil-based formulations

TABLE 1. This table compares organophilic clay concentration vs. rheological properties in mineral oil-based formulations.

 

Ensuring wellbore integrity

Several new technologies are being employed to provide continuous improvement to ensure wellbore integrity while capturing the intended benefits of flat-rheology invert emulsion drilling fluids. Micronized mineral weighting agents can be used in place of normal barite. Consistent with principles of Stokes Law, smaller suspended solids require a less viscous fluid to maintain suspension.

Additionally, considerable resources are being dedicated to automated fluids measurement (Figure 2). Simple properties such as density, rheology, and particle size distribution are accurately monitored on a continuously updated basis using new sensors and equipment. More complex apparatuses are emerging for determining chemical composition, including critical concentrations of emulsifiers, rheological modifiers, and organophilic clay, among other parameters. This information is fed back to specialized software that performs real-time hydraulics simulations while drilling, tripping, and running casing.



Ryan Shursen, M-I SWACO, a Schlumberger company

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