Optimizing initial production rate, reducing the need to re-enter the well and consideration of the individual well's role in optimizing production are key elements in modern stimulation design.

For many years the primary technologies under the "stimulation" label, acidizing and fracturing, have been shifting from what was a remedial role (fixing damage that occurred during drilling) to an enhancement role (optimizing initial production rates from an undamaged or minimally damaged well). Advancements in several areas have driven this shift.
Clean, low-solids drilling fluids and improved underbalanced drilling techniques make it much easier to safely drill wells without damaging productive formations. Better engineered completion fluids, cements and cementing procedures make it easier to maintain an undamaged formation during the completion process. And finally, newly developed perforating technologies minimize damage while maximizing access to the formation.
A growing focus on production enhancement and optimization has gained momentum with the growth of three other trends in the industry: wider application of horizontal wells in a variety of fields and reservoir situations, development of deeper, tighter gas resources and the move into deeper water offshore. Each of these trends calls for greater attention to initial production rates and completion technologies with an eye toward the entire life of the well and its role in the reservoir's depletion and the field's operation.
For example, with horizontal wells, optimizing production may require particular care to optimally treat all portions of a horizontal interval, since efficient drainage of the reservoir over time is dependent on taking full advantage of the horizontal completion. With deep gas completions, the high cost of drilling and fracturing requires that an optimal treatment maximize production rates, particularly if well spacing precludes additional wells to drain that portion of what may be a multiple interval reservoir. And with deepwater wells, many of which are often subsea completions, the high cost of re-entry makes it important to complete wells such that the need to re-enter the wellbore is minimized. In each of these cases, designing the completion's stimulation aspects should include an understanding of the longer-term needs of the well, reservoir and field.
"This can be difficult for some producers, particularly if it results in higher initial costs," said Rick Stanley, BJ Services business development manager for international stimulation. "But designing a completion and stimulation program with the whole field's development goals in mind can save money in the long run."
Stimulation and completion service companies are seeing more and more of their clients get them involved in multiple aspects of a field's development program, but the practice is not universal by any means. "Some companies employ a different approach in different parts of the world," Stanley said. "They might embrace a service company as a partner in an integrated development team in one region, but still compartmentalize things in the old 'drilling engineer-hands-off-to-completions engineer-hands-off-to-reservoir engineer' approach in another part of the company, keeping the service company involved in only one facet of the work." Stanley sees truly integrated services as making up perhaps 10% to 15% of the market for stimulation services, while the remaining 90% to 85% will continue to be met on the basis of best-in-class decision-making on the part of operators.
Stanley agreed production optimization is also more about preventing problems than remediation. For example, operating companies have developed sand production prediction software that, based on input from production logs, can predict the likelihood of sand flowback from a fracture-stimulated well producing at high drawdown. This in turn has led to the development of products like BJ's Flexsand, an additive that helps control proppant flowback without reducing fracture conductivity. Flexsand consists of deformable particles that help cushion the proppant from damage when a fracture closes and then lock the proppant in place during flow. "This is an example of a stimulation treatment feature that reduces the need to re-enter a well while at the same time maximizing productivity," Stanley said.
Another example is the trend toward premium, lower-polymer fracturing fluids worldwide, particularly in North America. During the past 2 years, Stanley said, treatments pumped in North America have been split among slickwater linear gels, conventional crosslinked gels and premium fluids. Before that, crosslinked gels had a much larger market share. Premium fluids are less likely to damage the formation, while still providing the characteristics necessary to carry out an optimum stimulation, again avoiding a new problem rather than fixing an old one.
Despite advances in stimulation technology, one factor has not changed: the reluctance of producing companies to give new technology a chance on wells where the payoffs might be the largest. The tendency remains to choose the worst problem wells for new stimulation methods, even if those methods are beyond the field testing stage. Giving service companies some say in the candidate selection process could change this, and possibly lead to more rapid demonstration of the potential of new technologies and their more widespread application. "The key is developing trust between the operator and service company," Stanley said. "Once that is in place, the potential for truly optimizing production across the life of a field becomes greater."
Coiled tubing
Another area in which technology advancements have led to more effective ways of optimizing production is through the use of coiled tubing (CT). Fracturing with CT is becoming an effective way of stimulating multiple zone wells economically. The CT is used to set an isolation packer across a perforated interval, fracture a zone, move to a new zone, reset the packer and repeat the process. Not only can this be accomplished in a fraction of the time required by a conventional rig, but compared to other multiple-interval stimulation alternatives there is a higher likelihood that every zone will be stimulated appropriately. As a result, overall production is enhanced.
CT services is one of the fastest growing oilfield technologies, with the global fleet of CT units having more than doubled during the past 10 years to nearly 1,000. At the end of 2001, an estimated 244 units existed in the United States and 199 in Canada, with the Canadian count expected to grow to more than 200 by early this year. About 27 CT companies operate in the United States, and about 38 operate in Canada.
CT is gaining in popularity in situations where it enables operators to reduce the cost or improve the effectiveness of completion, workover and drilling operations. The capabilities of the equipment, tubing, units and tools have improved tremendously during the past decade.
Initially, CT was employed primarily as a technique for well cleanout. This application, as well as acid stimulation, still accounts for more than three-quarters of CT revenues. However, drilling and fracturing applications, practically unknown a decade ago, make up nearly 15% of CT revenues. While hundreds of wells were drilled in Canada and the United States using CT, including directional re-entries and new shallow vertical wells, only a relatively small portion of the global CT rig fleet is capable of handling the larger tubing sizes (larger than 2 1/2 in.) typically needed for drilling.
Said Andy Rike, president of Technicoil USA Corp., a CT service company with operations in Canada and the United States, "We see market growth for coiled tubing services in three areas: fracturing, particularly multiple interval completions; re-entry drilling of horizontal laterals or vertical extensions in older wells; and grassroots drilling of shallower wells, including many coalbed methane (CBM) wells."
Rike added one of the most important reasons for growth of CT drilling services has been the development of more integrated units. "In past years, coiled tubing units were not able to provide the sort of integrated set of equipment capabilities needed for drilling, completion and stimulation operations. This led to an amalgamation of service company systems cobbled together onsite and a situation where the safety, speed and size advantages of CT were being lost." Technicoil as well as several other companies have designed and built integrated CT units that incorporate everything needed to drill and complete a well into a few trailer loads. When rigged up, these units fill a footprint less than one-third that of a conventional rig.
Fracturing, particularly multiple interval fracturing, is an expanding application for CT's capabilities. One recent example noted by Rike was a five-well project in Virginia's Buchanan County, where up to 19 intervals were fractured using CT and a bottomhole packer assembly. These wells, part of a Consol Energy Inc. CBM project, were part of a pilot to determine if individually fracturing each of the zones would result in better recovery.
Prior stimulation efforts evolved from single-stage, limited entry treatments to multiple-stage treatments with composite frac plugs and frac baffles. However, core tests on offset acreage revealed three out of 10 coal seams had not been stimulated by these treatments, and on average, 10 ft (3 m) of coal in each well was not effectively stimulated. If the CT fracturing approach is successful in improving this situation, Consol calculated an additional net present value of US $1 million could be added per 160-acre lease, based on a gas price of $2.50/Mcf. The CT fracturing procedure was a technical success, and when the wells are dewatered and fully evaluated, operators hope it will be an economic success as well.
Other CBM areas have seen similar success. For example, Barrett Resources experienced a 1.5-fold increase in gas production from 14 CBM wells in the Raton Basin following stimulation with CT vs. conventional treatments. "Fracturing is probably the area with the greatest growth potential," Rike said, "and coalbed methane is about a third of that market." When an operator needs to limit the time spent fracturing multiple intervals, CT is an option to consider.

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