Fracturing and gravel packing: one objective, different approaches
PerfPac, a joint Dowell and Schlumberger Wireline product, offers integrated tubing conveyed perforating, fracturing, and gravel packing, and test tool components in one downhole trip. Fracturing and gravel packing, sometimes known as "frac-pack," has been an option for completing wells in unconsolidated sand reservoirs since the process was pioneered in the Hackberry Field (Louisiana) in 1964. The term dates back to the 1950s, according to R.C. Ellis of Pennzoil.
Various systems reduce cycle times, formation damage
PerfPac, a joint Dowell and Schlumberger Wireline product, offers integrated tubing conveyed perforating, fracturing, and gravel packing, and test tool components in one downhole trip.
Fracturing and gravel packing, sometimes known as "frac-pack," has been an option for completing wells in unconsolidated sand reservoirs since the process was pioneered in the Hackberry Field (Louisiana) in 1964. The term dates back to the 1950s, according to R.C. Ellis of Pennzoil.
Over the last 30 years, advanced tools, techniques, fluids, and proppants have evolved to offer a variety of attractive methods for increasing production in highly permeable formations. Milestones such as the development of the tip screen out (TSO) hydraulic-fracture stimulations in the late 1980s offered sustained productivity improvements.
These TSOs were later combined with a gravel-pack screen-packer assembly to create short, highly-conductive fractures that bypass damage near the wellbore.
In this design, the gravel-pack screen would act as a barrier to prevent proppant flowback. Backed by the support of the gravel-pack, the proppant interacts with the formation, creating an effective barrier that prevents sand production and increases effective wellbore radius.
Early applications of this TSO hydraulic fracture on deviated wells in the Gulf of Mexico were hampered by the inadequacy of gravel packing tools, which could not handle the proppant volumes and pump rates required for a frac pack. Further improvements in these tools eliminated the need for a second pumping job to set the gravel after the screen assembly was run.
The elimination of this second pumping job proved to be the key to accelerating the use of frac pack. Because of the substantial cost savings in terms of rig time, use of this screen-in-place method became widespread. As the application of this time saving procedure spread, further improvements followed. Frac pack became the standard application for sand control and improvement of production sustainability. According to Ellis, the reliability of this process for sand control is very high. He reports that participants in a 1996 forum of frac pack noted only two sand control failures in the hundreds of frac jobs conducted worldwide over seven years.
Further developments in frac pack and perforation include:
- Hydraulic set packer
- High temperature fluids
- Breakers that allow for zero and sometimes negative skins
- Advanced propellant charges that penetrate casing and cement without damaging the formation
- Single run systems that perferate, pack, and produce from the same string.
Tool systemsA joint Dowell and Schlumberger Wireline product, PerfPac, offers integrated tubing conveyed perforating, fracturing, and gravel packing, and test tool components in one downhole trip. This single trip completion system, according to the developers, allows a minimum of fluid loss to the formation and reduces the completion time for gravel-packed completions by eliminating the additional trip for the bottom-hole assembly.
After perforating and killing the well, the operator unsets the perfpacker, moves the assembly down through the perforation zone, where it becomes the sump packer when the operator sets the gravel-pack packer.
Perf Pac also can perforate in underbalanced and well control conditions using an intelligent remote implementation system to communicate between the tubing and the annulus. This eliminates the "U-tubing" phenomenon that can occur while unsetting the perforating packer.
After perforating, which can be done using any of a variety of firing heads, such as BHF, HDF, and TCF, the guns fall off into the rathole, released by the SXAR mechanism. This technique eliminates the need for shock absorbers above the guns. PerfPac uses a drop bar firing system, allowing the service tool, after repositioning, to be converted to commence the gravel and frac pack operations. This process saves rig time and currently is being applied in the Gulf of Mexico and off West Africa. Perfpac differs from traditional frac packing, according to the developers, in that it can integrate and combine these services into a one-trip procedure.
Paul Palthe of Dowell Schlumberger says the process eliminates the need to come back out of the hole, set down the guns, pick up the gravel pack assembly, and run back downhole. This trip out would require the use of loss circulation material pills which can result in production impairment.
So, in addition to shortening rig time, this system reduces the potential for damage to the formation that can result from the use of a salt pill, calcium carbonate pill, or gel pill, which would otherwise be needed to invade and block the perforations, and maintain the positive differential between the well bore and perforations while the string is tripped out of the hole.
In the cleanup process, the loss circulation material would have to be removed using an acid treatment, impairing the number of perforations. Also, the acid can create leak-off to the formation, which breaks down some of the perforations, drawing all the acid to one point. By avoiding this trip-out all the perforations are protected and additional damage to the formation is avoided.
Palthe says the next step in efficiency will be the elimination of yet another trip by replacing the mechanical set packer with a hydraulic set packer. This would allow the operator to run downhole with a set of guns, perforate, then slack off with the gravel pack assembly. Because it is a hydraulic set packer, the operator will be using the production string for these procedures, eliminating the separate workstring.
The operator in this case can land a hanger and begin production, leaving the service tool downhole. This "Propac" system has been tested on the upper zone of one client's well in the Gulf of Mexico, using wireline guns, and running the gravel pack assembly made up to the production pipe. In this case, the single selective completion was done in 4.3 days, as opposed to the traditional eight for the standard two-trip procedure. Palthe said that Propac will be on the market by year's end.
At the same time, Halliburton has created a single trip PerfPac completion system (STPP) that can perforate, complete, and clean up a well in a single run, but requires a separate trip for a production string. The STPP system uses a mechanical packer, combined with a perforating system that can be dropped below the sump pack after it is used.
David Walker, Production Line Manager for OSCA, said his company has a single trip perforate and gravel pack system using the company's "Set Down Frac Service Tool" technology. This system allows set-down weight to be maintained on the assembly in either the squeeze or circulating positions, allowing maximum flexibility and reliability in designing and executing frac pack well treatments.
In the circulating position, a valve is opened in the bottom of the service tool allowing fluid circulation and bottom hole pressure transmission from the washpipe below the packer to the annulus above. The annulus is sealed at the surface using a conventional blowout preventer system. This enables the operator to monitor real-time bottom hole treating pressure. The operator can accurately detect events such as fracture initiation, tip screen out, and wellbore sand out.
While many tools may be modified to provide either set down circulating or set down squeeze positions, the OSCA system allows the flexibility to do both with up and down tool manipulation. Maintaining set-down weight while treating eliminates the possibility of unwanted tool movement occurring during the job due to temperature and pressure effects on the workstring.
If not accurately prevented or allowed for, this movement may cause failure of the frac pack treatment and sticking of the service tools. The set down feature also allows alignment of the service tool slurry exit ports and the gravel pack extension exit ports.
This feature reduces the chances of packing sand between the service tool and gravel pack extension which could cause service tool sticking. In the event the bottom hole treating pressure becomes too great for annular restrictions above the packer, the tool may be shifted to the squeeze position eliminating pressure communication above the gravel pack packer.
High angle risksTommy Grigsby, Technical Analyst for Halliburton, said long interval, high angle wells are a difficult environment for these type of single trip tools. Perforation creates quite a bit of debris that generally falls to the bottom of the wellbore. When the bore is not vertical, then this debris can pile up, sticking the guns, and possibly clotting formation sand. In the Halliburton design, the perforation guns do not fall away. They are instead run through the big bore sump packer (BBP).
The packer has a large internal diameter, relative to the pipe. Once the perforation is complete, weight on the tubing is used to push the perforating guns down through the big bore sump packer sealing off against this packer and providing the mechanical seal with the guns below the BBP. The top packer is then set above the screens and the well is ready to be fractured.
Sanjay Vitthal, Technical Specialist for Halliburton said, in cases where there are expensive completion fluids involved in a fluid loss situation, the savings realized by these new systems add up quickly. In some cases, the savings in completion fluid costs and rig time have been as high as $1 million.
In the near future, Halliburtion will apply new technology it has used for sand control problems off China to frac jobs in the Gulf of Mexico. Vitthal said the company is now able to perform sand control on two formations, that are reasonably close together, in one trip.
Traditionally an operator would perform a sand control job on one formation, then trip out, add the next assembly, trip this down to the second formation, attach it and do the second sand control job. This new technology allows the company to do both jobs in one trip. The operator simply trips in with the whole gravel pack tool assembly for both jobs.
These tools are currently being adapted to perform frac packs in the Gulf of Mexico. One drawback to this operation is that it requires pay zones that are similar in pressure. Because both of these zones will be open at the same time, the bottom hole pressures of the two zones need to be close enough that they both can be controlled with the same fluid, without damaging either zone. If the pressures are similar, the two zones could be several hundred feet apart.
In addition, Halliburton also is focusing on fracpacks as a way of eliminating screens in some formatons. Since these treatments often can be performed without a rig on location, there can be signficant cost savings. For instance, Vitthal said Halliburton performed a screenless frac pack in a well with a total depth of about 14,000 ft. Because there was no screen in the hole, the job did not require a rig or completion fluids. At this depth, the cost of filling a drill stem with completion fluids would have cost close to $500,000, more than the frac job itself.
Frac fluid advancementsIn the beginning there were hydroxyethyl cellulose (HEC) fluids. These clean, polymer-based fluids would dissolve in water and create viscosity levels high enough to fracture formations, without causing a large amount of damage. The HECs then gave way to gels such as borate cross-link fluids.
The boron ions in cross-link guar-based fluids allowed chemists to create a sturdy mesh of polymer chains, which Vitthal compares to a chainlink fence. The development of these cross-linked fluids represented a paradigm shift in viscosity levels, jumping from 100 centipoise to ten times that amount.
The borate ion is sensitive to the pH level of the formation. At a pH of eight or more, the viscosity would rest in the 1,000 centipoise range, but below that level the viscosity plummets to as low as 30 centipoise. Because the natural pH level in the formation, outside the bore hole, is below seven, this trigger level meant an operator could enjoy a very high viscosity during the fracture treatment and then see the level drop very low as the formation reduces the pH of the fluid over time. This quick transition helps with production by avoiding damage to the formation, and allowing the formation to flow, pushing the gel out of the hole.
Over the last three years, use of the HEC fluids has given way to widespread use of borate cross-link fluids. "Over the last two years, out of the more than 100 jobs Halliburton has pumped, 95% have been with borate cross-link fluids," Vitthal said.
On the horizon now is a product that can avoid even the minimal damage created by these guar fluids. Currently, only 30-50% of a fracture's potential is realized after a frac pack due to formation damage. Ideally, a reservoir will produce with a skin of 0, but realistically, that skin, even with frac pack, is in the neighborhood of 2.5. These skin numbers are good, compared to those delivered by gravel packs, in the 20 range, but can be improved upon.
Vitthal said because the frac pack increases the surface area for flow, it is reasonable to expect zero or negative skin numbers in many cases if there is little or no formation damage. To overcome the damage from these fluids, Vitthal said Halliburton looked at reducing the gel load, or amount of polymer used in these fluids. Not only would this reduce damage to the formation, but it would be a less expensive system.
This new system (Delta FraPac) is able to triple the conductivity of the fracture with no damage at all. "We've done around 30 jobs (with the new system) and the skins we are seeing average around -2," Vitthal said.
The chemists lowered the gel load in the fluids by 30% by improving the cross-link efficiency of how the borate ion ties the polymers together. The chemists also developed new chemical breakers for the fluid. Traditional breakers react with both fluids and rocks and are therefore very inefficient. By changing the breakers so that they react mainly with fluid, the chemicals are able to produce clean fractures.
Another fluid improvement, that may seem basic, but was helpful in reducing cycle times, is designing this new generation of fluids so that it could be mixed with seawater rather than fresh water, which has to be shipped in from the mainland.
This has helped to increase service availability. The gels also can be mixed "on the fly" and hydrate instantly. This means that the fluid properties can be tailored for each formation.
Kiss chargesOne source of formation damage is the perforation, which creates debris not just from the formation, but from the guns themselves. Marathon Oil has measured this debris to be as high as 5 lb/perforation, about 6,000 lbs. of damaging material generated every time a well is perforated. This translates into over 100 ft using a standard 12 slots/ft configuration.
To overcome this, Halliburton is working on a "kiss" charge and a combination system composed of smaller charges and a high velocity propellant gas. The idea is to penetrate only the casing and cement sheet, barely cutting the formation. This would eliminate the "crush zone." While the small charges clear the casing and cement out of the way, the propellant will fracture and expose the formation using a high-velocity gas that can penetrate the formation, but does not sending any debris into the formation. In addition, Halliburton is moving away from the traditional spiral perforation pattern, shooting 12 holes/ft in different directions in favor of a gun that shoots only 8 holes/ft, all in a straight line. These perforations line up with the fracture in the formation so that all the holes can produce simultaneously. This is especially attractive in deepwater fields, where high production rates put a lot of strain on the capacity of traditional perforation patterns.
SurfactantsChris Cornelius, Technical Marketing Manager for OSCA, said the company has developed a new line of super surfactant viscoelastic fluids with a temperature extension he claims reaches as high as 450°F. These fluids can be mixed with conventional brines or seawater. In fact, they work better with filtered salt water than fresh water.
The fluid has similar rheological characteristics as the borate gels, while the viscosity can be tailored to treatment needs over the range 100-350 centipoise, but maintains these levels at high temperatures.
These super surfactants are non-damaging fluids that leave no gel residue in the formation or proppant pack because they are not polymer based. Though the fluid has yet to be field tested, Cornelius said, under test conditions at Stimlab, the new fluid has retained conductivity of 100%, as compared to about 35% for conventional fluids.
Advanced breakersBrian Evans, Section Leader for Sand Control and Completions at BJ Services, said his company is making great advances in developing breaker systems for drilling fluids using site specific enzymes. BJ optimizes enzymes to break down polymers in specific places.
So, if a client has a cross-link fluid or a certain polymer he is running, these enzymes will not just reduce the viscosity, but break it, maximize returned permeability, and minimize reservoir damage from polymer residue.
On horizontal gravel packs, which are open holes, it is necessary to leave the filter cake in place. If the formation is sensitive to acid, then these enzyme treatments offer a safe option. The new treatments can eat out most of the filter cake so the well can be produced without the acid treatment. These enzyme soaks also are used after acid treatments, if the permeability level is still low. This would clean out any remaining polymers left in the formation.
For frac packs, Evans said encapsulated breakers are the company's latest development. The breaker chemicals are applied to a nonreactive substrate and coated. These coatings can take about 12 hours to dissolve. These breakers are pumped down with the proppant fluid. On big jobs that pump for many hours, these encapsulated breakers buy the operator some time before they begin to break down the polymers of the fluids.
References:Richard C. Ellis is a senior petroleum engineering advisor with Pennzoil E&P Co., his article "An overview of Frac Packs: A technical Revolution (Evolution) Process", SPE 39232, was referenced in the creation of this article.
Copyright 1998 Oil & Gas Journal. All Rights Reserved.