As stimulation technology gives life to new reservoirs and old, completion and fracturing are becoming
more closely involved with one another. The two can be thought of as a single step in some cases,
with new-generation equipment and technology making the process more efficient.


Many of the reservoirs that interest producers today have already had a productive life. But new technology finds a lot of reserves that are now recoverable, and well stimulation is called for.
The technology applies as well to new reservoirs at the beginning of production. Stimulation is a big topic, involving both acidizing and fracturing. And it's changing. For one thing, completion and fracturing are becoming more closely involved with one another. And new-generation equipment and technology makes the whole process more efficient.
At Marathon Oil, senior technical consultant Phil Snider is putting the new Excape Completion Process into its first wells. Developed by Marathon and partners, the Excape system is a perforating gun system mounted outside of casing and cemented in place with the casing. When fired, the guns perforate formation and casing. But the Excape system is more than a new way of perforating. It aids in the stimulation job and can improve performance of every zone in the well, as isolation devices are incorporated into the casing string below each perforating gun.
The first well completed using the system, in Canada in mid-1999, involved four zones at 2,500ft. The well is making 5 MMcf/d, about double the rate of offset wells, indicating substantial opening up of the near formation by the perforation process. The external perforating system perforates the formation and isolates the lower intervals so fracture stimulations can proceed without working inside the casing. Other factors behind the increased production are probably "the speed of treatment so that treatment chemicals are not left in contact with the formation for extended periods of time," Snider said.
"There have been hints for years that frac fluids could be improved," Snider said. Gaining an effective frac length of 50 to 100ft when pumping 300 to 400ft is just one typical hint. Marathon already has used BJ Service's Vistar in Canada to investigate lower gel loading frac fluids. Also Marathon is checking viscoelastic fluids and microemulsion fluids. And many operators such as UPRC and Anadarko routinely pump water with little or no proppant in it and get good fracturing results.
"Following the lead of Dick Ellis when he was at BP and Pennzoil, we're now routinely fracturing high-permeability wells," Snider said. Marathon is moving toward fracturing every well, even in highly permeable rock, and certainly frac packs every sand control well in the Gulf of Mexico and other parts of the world except for long horizontal bores.
"In a low-permeability formation production can go from 50 b/d to 300 b/d, which is a big percentage increase. High-permeability formations can go from 8,000 to 10,000 b/d or to 12,000 b/d. Not such a high percentage, but plenty of oil."
Point-source perforating
Chevron has found success in its South Texas operations departing from the standard practice of perforating every foot of net pay.
Instead, the company focuses on perforating for stimulation, selecting what is best for stimulating the formation and maximizing post-fracture production. This method incorporates point-source perforating as deployed by the Gas Research Institute and its contractors during the 1990s. Chevron's approach is unique, however, in that "only 5ft is perforated, and that is in the bottom third of the interval in poorer quality pay above a silty section," said Chevron petroleum engineer Robert Lestz. "This strategy takes advantage of any proppant settling and bridging in the silty sections, thus helping to assure that the perforations remain connected with the fracture."
These benefits coupled with point-source perforating have resulted in fractures that are outperforming wells perforated for production due to a single frac being created that is more conductive, effectively longer and remains connected to the fracture. An additional benefit in placing the perforations toward the bottom of the interval is that it provides an opportunity to plug back to the better reservoir if the results are unsatisfactory or the zone is damaged later.
"We have recognized point-source perforating improves your ability to successfully stimulate an interval and gone the next step by placing the perforations at the bottom of the interval to improve our completions and ultimate recoveries," Lestz said. "We have learned from perforating for stimulation that it does not take 100ft of perforations to produce a 100ft zone. We have proven that 5ft placed in the proper place will outperform perforating all 100ft."
Measuring the results
Part of the reason for successes of innovations such as casing-conveyed perforating and point-source perforating followed by fracturing comes from measuring the results at each perforation site.
Using zero-wash isotope tracers and logs, Core Laboratories' ProTechnics Division measures proppant uptake in all zones immediately after a fracture and diagnoses flow from each one as well. As ProTechnics' Buddy Woodroof explained, this permits doing stimulations that used to take weeks in a few hours or a day. A poorly flowing zone can be isolated and fractured again immediately before moving up to the next stage.
The latest measuring instrument in this area is ProTechnics' Completion Profiler, introduced in mid-1999. When run in conjunction with the SpectraScan Imager, the profiler tells where proppant is and what flow rates are, zone by zone.
Demanding frac packs
Baker Oil Tools (BOT) has put into service its new XOTMove and XOTLive software to predict performance of its CK Fraq frac packing system. This system is designed for high-erosion resistance in demanding situations where crossover tool failure could be catastrophic. "It has proved indestructible after 450,000lb of proppant were pumped in third-party tests specified by a customer," said BOT fluids product line manager Carroll Newman. "The best competitive tools failed after 225,000lb," Newman said. The XOTLive software predicts the wear the tool will encounter and calculates tool life during treatment procedures. It also provides data for redesign of the fluid to avoid tool erosion.
BOT's companion XOTMove software forecasts hookloads due to manipulation of workstrings during gravel packing and stimulation. "With the increasing complexities of these operations in deepwater today, we need the prediction software so crews can detect movements, drag, friction or unanticipated buckling or tool cycling," Newman said.
Particle treatment
BJ Services has just introduced high-horsepower pumping equipment called the Gorilla and is field-testing three styles of pumps with three different transmissions. Two of the efficient 2,700hp units can equal the fracturing performance of five conventional trucks.
BJ has commercialized its Flexsand system for fracturing to prevent proppant flowback. Flexsand, experimental in February 1999, has been involved in more than 80 treatments.
Individual Flexsand particles are deformable and the same size as proppant grains. In a pack the particles dimple and deform with the proppant grains and form an embedded yet porous pack.
In proppant flowback tests where four times the expected flow and four times the pressure increase are involved, performance has always exceeded the standard, said BJ Services research engineer Chris Stephenson.
BJ Services has developed several case histories of frac treatments with the Flexsand system. Since Flexsand is a particle like the proppant, it absorbs pressure and prevents damage and fines production.
The company is developing products to extend the pressure and temperature range of applications and plans families of products spanning the range of 100° to 400°F and 100 to 15,000psi.
Vistar fluid is a low-polymer-load frac fluid that results in better cleanup and productivity from the well. Wells have low pH and low CO2. It delivers the same or better performance with half the polymer load of conventional fluid.
Other developments include a new surfactant for fracturing fluid, Floback 30. It facilitates the cleanup of frac after treatment and keeps polymer in solution to clean it out. Results show 20% better productivity.
Coiled tubing advance
Schlumberger's well stimulation activities include expansion of its CoilFrac Service, which began in Canada, now is in the United States and soon will be in South America and the North Sea, said Kamel Bennaceur, marketing manager for well production services.
CoilFrac consists of a coiled tubing (CT) unit with Pumper-Blender Pod, truck-mounted with 1,000hp. "With this equipment we can do up to 10 fracs in different zones in one well in one day. This would take several days to do the old way," Bennaceur said. The bottomhole assembly isolates each zone without pulling out of the hole. Production from the wells is always higher because the CoilFrac service accesses more intervals, exploits bypass pay and doesn't damage the formation.
CT sizes used are 1¾in. to 23/8in. The service can pump up to 10 bpm at surface pressures to 12,000psi. Frac jobs in Canada in the past have typically covered five zones, taken 14 days and required 45 different operations. The new CT units can stimulate five zones using 15 operations in less than 4 days.
In the past year or so, Schlumberger has replaced many of its frac fluids that use polymers with viscoelastic, surfactant-based systems containing no polymer loading. The fluid typically carries three additives compared to 10 additives in conventional fluids. Schlumberger uses the new fluid, ClearFrac, in nearly# all its markets. The fluid is usable in wells with bottomhole temperatures up to 250°F and will be able to handle 350° by mid-2000.
ClearFrac is a low-friction fluid requiring less pumping power. It's a clean fluid that can be mixed with required additives on the fly so no waste is involved. The company has also modified its PropNet technology, adding new fibers that work above the previous 450°F limit and are installed via a new dry additive system, which simplifies blending and job execution.
Other enhancements Schlumberger reports include its PowerStim service, which integrates petrophysical and geological information into the completion recommendation and the stimulation program, and the AllPac system (a joint development with Mobil), which extends gravel packing to horizontal wells and intervals longer than 4,000ft using shunts to pack intervals completely.
A new PSP Log gives a three-phase description of flow entering wellbore in a horizontal well - the amount of oil, water and gas through the interval - and then identifies water sources and gas sources. Traditional PLT measurements are not good in horizontal wells. From the PSP log, operators can decide whether to stimulate or shut off an interval or abandon the branch and drill another lateral.
Integrating completion, stimulation
Halliburton has combined completion products with production enhancement - fracturing, acidizing and sand control - to better integrate the completion process and improve efficiency. Reducing cycle times and getting a better focus on the reservoir with smart wells and related new technology are major objectives.
The company is combining stimulation design and treatment with the MRIL Log (StimMRIL) - integrating the porosity, permeability and reservoir temperature and pressure to optimize the stimulation treatment and more accurately estimate production. Together with conventional logs, the MRIL measurement, which gives pore volume directly, presents a much better picture of the formation. With direct information on the pore fluid from the MRIL log, operators have improved field economics by plugging and abandoning wells that they may have otherwise stimulated.
Halliburton's Sand Wedge service, one of the newest technologies to emerge from its ongoing research and development into enhancing well productivity, improves fracture conductivity by reducing the beta factor.
"Sand Wedge is a conductivity enhancement material that has led to longer effective fracture lengths and increased initial production. This allows an operator to better optimize his treatments volumes," said John Podowski, Halliburton's strategic business manager for production enhancement.
Another factor is cycle time reduction. "Anything you can do to get your wells completed and on production quickly translates to improved NPV (net present value), so we focus on technologies related to cycle-time reduction," Podowski said.
Composite bridge plugs are an example. "When we do multiple stages, we can run in with wireline and set a composite plug and isolate a zone, perforate it and frac in the same day. After all the stages are completed, we can go in with coiled tubing and drill the composite plugs out to combine production from multiple zones," Podowski said.
Another thing Halliburton has tested in Canada is a packer assembly, run on the bottom of CT. This is a straddle-type assembly with a built-in bypass to allow it to equalize pressure. The company said it has placed in excess of 60 million lb of proppant in nearly 2,300 jobs in 1999. It uses the same assembly on hydraulic workover or snubbing units to restimulate the higher temperature and pressure wells. No squeezing or plugging is required.
Looking further into cycle-time reduction has led Halliburton to higher pressure pumping units. "Our HT 2000 new-generation equipment allows us to go to 20,000psi without intensifiers. This tremendously reduces the amount of equipment on location and the number of people required for higher pressure treatment," Podowski said. "The HT (horizontal triplex) pump is still a plunger pump, but a new Halliburton-designed fluid end has vastly improved fatigue life.
"It used to take a day to rig up with intensifiers, and now we rig up in the morning and frac at 20,000psi and rig down and go on to the next one. So it's taken a day of our rig up."
Big boats
Halliburton put a big new well stimulation vessel - the StimStar - in Gulf of Mexico service early in 1999. Then late in the year Schlumberger and BOT introduced stimulation vessels within days of one another. Schlumberger's DeepStim has a nominal 12,700 hydraulic horsepower (hhp), increasable to 12,700 with pumping rates of 50 bpm. The RC Baker features 8,000 hhp, expandable to 11,000, dynamic positioning to within 10ft, 1 million-lb sand storage in pneumatic tanks, 189,000-gallon batch mixing capabilities and high-rate pumping.