Isolate and Stimulate Individual Pay Zones

Transcription

1 Isolate and Stimulate Individual Pay Zones Coiled tubing-conveyed fracturing is a cost-effective alternative to conventional reservoir-stimulation techniques. This innovative approach improves hydrocarbon production rates and recovery factors by providing precise, reliable placement of treatment fluids and proppants. What began as a fracturing service is evolving into broad technical solutions for new completions, as well as workovers in mature fields. Kalon F. Degenhardt Jack Stevenson PT. Caltex Indonesia Riau, Duri, Indonesia Byron Gale Tom Brown Inc. Denver, Colorado, USA Duane Gonzalez Samedan Oil Corporation Houston, Texas, USA Scott Hall Texaco Exploration and Production Inc. (a ChevronTexaco company) Denver, Colorado Jack Marsh Olympia Energy Inc. Calgary, Alberta, Canada Warren Zemlak Sugar Land, Texas ClearFRAC, CoilFRAC, CT Express, DepthLOG, FMI (Fullbore Formation MicroImager), Mojave, NODAL, PowerJet, PowerSTIM, PropNET, SCMT (Slim Cement Mapping Tool) and StimCADE are marks of Schlumberger. For help in preparation of this article, thanks to Taryn Frenzel and Bernie Paoli, Englewood, Colorado; Badar Zia Malik, Duri, Indonesia; and Eddie Martinez, Houston, Texas. Operators traditionally rely on drilling programs to achieve peak productivity, maintain desired production levels and optimize hydrocarbon recovery. As oil and gas developments mature, however, reservoir depletion reduces field output and fewer opportunities exist to drill new wells. Drilling programs alone may not effectively stem the natural decline of production. In addition, infill and reentry drilling often become less profitable and present greater operational and economic risks relative to their higher capital investments. In many fields, operators intentionally and unintentionally bypass some pay zones during initial phases of field development by focusing only on the most prolific producing horizons. Cumulatively, these marginal pay intervals contain substantial hydrocarbon volumes that can be produced, especially from laminated formations and low-permeability reservoirs. Accessing bypassed pay zones is economically attractive to enhance production and increase reserve recovery, but poses several challenges. Typically, bypassed zones have lower permeabilities and require fracturing treatments to achieve sustainable commercial production. Conventional well-intervention and stimulation methods involve extensive remedial operations, such as mechanically isolating existing perforations or squeezing them with cement and utilizing multiple runs to perforate bypassed pay. These procedures are expensive and cannot be justified for zones with limited production potential. In the past, fracture stimulations were not commonly attempted on bypassed pay, especially when multiple stringers were involved. The mechanical condition of wellbores can be a limitation as well. If fracture stimulations are not anticipated during well planning, completion tubulars may not be designed to withstand highpressure pumping operations. Also, scale buildup and corrosion from prolonged exposure to formation fluids at reservoir temperatures and pressures can compromise tubular integrity in older wells. In slimhole wells, workover options are further limited by small tubulars. These operational and economic constraints often mean that bypassed or marginal pay remains untapped. Ultimately, hydrocarbons in these intervals are left behind when wells are plugged and abandoned. Integration of coiled tubing with fracturing operations overcomes many of the constraints associated with stimulating bypassed or marginal pay zones using conventional techniques, allowing additional reserves to be tapped economically. High-strength continuous coiled tubing strings transport treatment fluids and proppants to target intervals and protect existing wellbore tubulars from high-pressure pumping operations, while specialized downhole tools selectively isolate existing perforations with increased precision. 60 Oilfield Review

2 > A fit-for-purpose CT Express coiled tubing unit performing a selective fracturing treatment in Medicine Hat, Alberta, Canada. Autumn

3 This article describes operational and design aspects of coiled tubing-conveyed fracturing treatments, including enabling technologies such as surface equipment improvements, high-pressure coiled tubing, low-friction fracturing fluids and new downhole isolation tools. Case histories demonstrate how this technique reduces completion time and cost, improves post-treatment cleanup, increases production and helps tap reserves bypassed by conventional completion and fracturing methods. Conventional Stimulations Average recovery factors for most reservoirs from primary- and secondary-drive mechanisms are just 25 to 35% of original hydrocarbons in place. Producible reserves also are left behind in thin, lower permeability zones of many mature reservoirs. One North Sea study, for example, determined that more than 25% of recoverable reserves lie in the low-permeability, laminated horizons of Brent sandstone reservoirs. 1 Matrix acidizing and hydraulic fracturing are common reservoir-stimulation techniques used to enhance well productivity, increase recovery efficiency and improve well economics. 2 However, effectively completing and stimulating heterogeneous reservoirs and discontinuous pay zones among numerous shale intervals are challenging, particularly when fracture stimulations are required. Reservoir pay thickness, quality, pressure and stage of depletion, and cost to treat an entire productive horizon all must be considered when choosing completion strategies. Conventional fracture stimulations attempt to connect as many producing zones as possible with single or multiple treatments performed during separate operations. Historically, net pay zones over several hundred feet of gross interval are grouped into stages, with each stage stimulated by a separate fracturing treatment. These massive hydraulic fracturing jobs, pumped directly down casing or through standard jointed tubing, are designed to maximize fracture height while attempting to optimize fracture length. However, uncertainty associated with predicting height growth often compromises the stimulation objectives of large treatments and precludes creation of the fracture lengths required to optimize effective wellbore radius and reserve drainage. Proppant placement in individual zones is difficult to achieve when a single treatment is performed across numerous perforated zones (below). Thin or low-permeability zones grouped > Single-stage treatment diversion: radioactive tracers and production logs. With limited-entry techniques, some zones are not stimulated effectively and others may remain untreated. In this example, six pay zones over a 300-ft [90-m] gross interval were fractured through 24 perforations. A radioactivetracer survey shows that the three upper zones received most of the treatment fluids and proppant, while the three lower zones were not adequately stimulated (left). If an interval did not take fluid at the beginning of a treatment, perforation erosion in other sands eliminated the backpressure necessary for diversion. The lowest zone contributes no production; the other two contribute very little flow on the production log spinner survey (right). with thicker zones may remain untreated or may not be stimulated effectively, and some zones are occasionally bypassed intentionally to ensure effective stimulation of more prolific pay. Limited-entry perforations and ball sealers distribute fluid efficiently during pad injection, but less effectively during proppant placement as perforations are enlarged by erosion or treatment fluids flow preferentially into higher permeability zones. 3 Unintentionally bypassed and untreated zones also are attributed to variable in-situ stresses. In past conventional fracturing designs, the fracture gradient, or stress profile, was assumed to be linear and to increase gradually with depth. In reality, formation stresses often are not uniform across an entire geologic horizon, and again, some zones may be difficult to treat and stimulate effectively (next page, top). Grouping pay zones in smaller stages overcomes some of these limitations and helps ensure sufficient fracture coverage, but multistage treatments usually require several perforating and fracturing operations in succession. Isolating individual zones for conventional fracture stimulations with workover rigs and jointed tubing is problematic as well, requiring additional equipment and workover procedures. There are fixed costs associated with each stage of multistage fracturing operations. Conventional fracturing operations add redundancy to stimulation operations and increase overhead costs. Every time wireline units and pumping equipment are moved onto a wellsite for perforating and stimulation operations there are separate mobilization and setup charges. There are also separate coiled tubing or slickline costs to wash out sand plugs or set and retrieve bridge plugs, which have to be purchased or rented. Hauling, handling and storing stimulation and displacement fluids for each nonconsecutive fracturing operation involve additional costs. Testing each individual stage in a well again requires multiple setups and significantly increases completion time. Some gas wells with several large treatment stages may take weeks to complete. Redundant charges accumulate quickly on wells with more than three or four stages and significantly affect the economics of stimulation procedures. These higher costs typically become a major influence on completion or workover decisions and strategies and may limit development of marginal pay zones that cumulatively contain sizeable volumes of oil and gas. To stimulate bypassed zones in existing wells, conventional fracturing requires that lower producing zones be isolated by a sand plug or 62 Oilfield Review

4 Increasing depth > Variations in formation stress. In single, multizone treatments, pressure changes are assumed to be linear with depth (far left). Depleted zones cause pressure to decrease abruptly (middle left). Excessively depleted sands also reduce pressure over extensive intervals (middle right). In some cases, formations have pressure and stress variations that make diversion of treatment fluids and stimulation coverage during a single-stage treatment extremely difficult (far right). > Conventional and selective stimulations. Fracturing several zones grouped in large intervals, or stages, is a widely used technique. However, fluid diversion and proppant placement are problematic in discontinuous and heterogeneous formations. Conventional treatments, like this four-stage example, maximize fracture height, often at the expense of fracture length and complete interval coverage (left). Some zones remain untreated or may not be stimulated adequately; others are bypassed intentionally to ensure effective treatment of more permeable zones. Selective isolation and stimulation with coiled tubing, in this case nine stages, overcome these limitations, allowing engineers to design optimal fractures for each pay zone of a productive interval (right). downhole mechanical tool such as a retrievable or drillable bridge plug. Upper perforations are sealed off by cement squeezes that are often difficult to achieve, require additional rig time and add to completion costs. There also is a risk that squeezed perforations will break down during high-pressure pumping operations. These limitations, inherent in conventional fracturing techniques, reduce stimulation effectiveness. Unconventional well intervention and stimulation techniques are needed to ensure hydrocarbon production from as many intervals as possible, especially from zones that previously could not be completed economically. Coiled tubing-conveyed fracturing techniques overcome many of the limitations associated with conventional fracturing treatments (below left). 4 Selective Stimulations Combining coiled tubing and stimulation services is not new. In 1992, coiled tubing was used to fracture wells in Prudhoe Bay, Alaska, USA. The in. coiled tubing was connected into the wellhead and left in the well as production tubing to help maintain flow velocity. This technique never gained wide acceptance because it was limited to smaller intervals and lower treating pressures in wells where a single zone was targeted for completion. 1. Hatzignatiou DG and Olsen TN: Innovative Production Enhancement Interventions Through Existing Wellbores, paper SPE 54632, presented at the SPE Western regional Meeting, Anchorage, Alaska, USA, May 26-28, In matrix treatments, acid is injected below fracturing pressures to dissolve natural or induced damage that plugs pore throats. Hydraulic fracturing uses specialized fluids injected at pressures above formation breakdown stress to create two fracture wings, or 180-degree opposed cracks, extending away from a wellbore. These fracture wings propagate perpendicular to the least rock stress in a preferred fracture plane (PFP). Held open by a proppant, these conductive pathways increase effective well radius, allowing linear flow into the fractures and to the well. Common proppants are naturally occurring or resin-coated sand and high-strength bauxite or ceramic synthetics, sized by screening according to standard US mesh sieves. Acid fracturing without proppants establishes conductivity by differentially etching uneven fracture-wing surfaces in carbonate rocks that keep fractures from closing completely after a treatment. 3. Limited entry involves low shot densities 1 shot per foot or less across one or more zones with different rock stresses and permeabilities to ensure uniform acid or proppant placement by creating backpressure and limiting pressure differentials between perforated intervals. The objective is to maximize stimulation efficiency and results without mechanical isolation like drillable bridge plugs and retrievable packers. Rubber ball sealers can be used to seal open perforations and isolate intervals once they are stimulated so that the next interval can be treated. Because perforations must seal completely, hole diameter and uniformity are important. The pad stage of a hydraulic fracturing treatment is the volume of fluid that creates and propagates the fracture and does not contain proppant. 4. Zemlak W: CT-Conveyed Fracturing Expands Production Capabilities, The American Oil & Gas Reporter 43, no. 9 (September 2000): Autumn

5 > Coiled tubing-conveyed fracturing with a single tension-set packer and sand plugs. By 1996, coiled tubing-conveyed fracturing was identified as a preferred completion strategy for shallow gas fields in southeastern Alberta, Canada. 5 Selective placement of proppant in all the productive intervals of a wellbore reduced completion time and enhanced productivity. The best candidates were wells with multiple lowpermeability zones where gas production was commingled after fracturing. Previously, these wells were stimulated by fracturing one interval per well and then moving to the next well. While a fracturing crew treated the first interval of the next well, a rig crew prepared previous wells for fracturing of subsequent intervals. Extensive rig-up and rig-down times were required to treat as many as four wells a day. In terms of number of treatments performed, this process was efficient, but moving equipment from one location to another took more time than actually pumping the fracturing treatments. Operators evaluated the possibility of grouping zones into stages for conventional multizone stimulations using limited-entry perforating, ball sealers or other diversion techniques to individually isolate zones, but could not justify these standard industry practices economically. One solution was to use a coiled tubing tension-set packer and sand plugs for zonal isolation. The lowest zones were treated first by setting the packer above the interval to be fractured. Proppant schedules for each zone included extra sand to leave a sand plug across fractured intervals after pumping stopped and before treating the next zone. Each treatment was underdisplaced, and wells were shut in to allow the extra sand to settle into a plug. A pressure test verified sand-plug integrity and the packer was reset above the next interval. This procedure was repeated until all pay intervals were stimulated (above). The larger coiled tubing string was rigged down and smaller coiled tubing was brought in to wash out sand and initiate well flow. Coiled tubing-conveyed fracturing has since expanded to slimhole wells , and in. tubulars cemented as production casing and to wells with open perforations or questionable tubular integrity that prevented fracturing down casing. Conventional workovers and stimulations that require cement squeezes to isolate open perforations are expensive and risky under these conditions. Shallow gas and deeper coiled tubing stimulations in mature oil and gas regions of the continental region of the United States formed the basis for CoilFRAC selective isolation and stimulation services. In east Texas, USA, coiled tubing was used to stimulate wells with open perforations above bypassed zones and wells with low-strength in. production casing weakened further by corrosion. After the target zone was perforated, a tension-set packer on coiled tubing isolated the wellbore and upper perforations (next page, top left). In south Texas, bypassed pay zones between open perforations in wells with casing damage near the surface were stimulated successfully by setting a bridge plug below the target zone and then running a tension-set packer on coiled tubing (next page, top right). These fracture stimulations were performed without cementing existing perforations or exposing production casing to high pressures. Early CoilFRAC techniques with tension-set packers improved stimulation results, but were still time-consuming and limited by having to set and remove plugs. The next step was to develop a coiled tubing straddle-isolation tool that sealed above and below an interval to eliminate separate operations for spotting sand or setting bridge plugs with a wireline unit (next page, bottom). This modification allowed coiled tubing strings to be moved quickly from one zone to the next without pulling out of the well. 5. Lemp S, Zemlak W and McCollum R: An Economical Shallow-Gas Fracturing Technique Utilizing a Coiled Tubing Conduit, paper SPE 46031, presented at the SPE/ICOTA Coiled Tubing Roundtable, Houston, Texas, USA, April 15-16, Zemlak W, Lemp S and McCollum R: Selective Hydraulic Fracturing of Multiple Perforated Intervals with a Coiled Tubing Conduit: A Case History of the Unique Process, Economic Impact and Related Production Improvements, paper SPE 54474, presented at the SPE/ICOTA Coiled Tubing Roundtable, Houston, Texas, USA, May 25-26, Oilfield Review

6 > Coiled tubing-conveyed fracturing with a single tension-set packer for casing and tubing protection. > Coiled tubing-conveyed fracturing with a single packer and mechanical bridge plugs. In south Texas, a well with casing damage near the surface and a bypassed zone between existing open perforations was stimulated successfully with coiled tubing. The operator set a bridge plug to isolate the lower zone before running a tensionset packer on coiled tubing to isolate the upper zone and protect the casing. This technique eliminated a costly workover and remedial cementsqueeze operations. > Multistage coiled tubing-conveyed fracturing operation with early straddle-isolation tools. Autumn

7 Elastomer cup-type seals were added above a tension-set packer to isolate perforated intervals and eliminate separate plug-setting operations. However, additional modifications were required to further reduce time and cost. In Canada, an isolation tool with elastomer cups above and below an adjustable ported spacer assembly, or mandrel, was developed to allow multiple zones to be treated in one trip (right). This version of the straddle-isolation tool, which had no mechanical slips to facilitate quick moves and fishing, carried shallow-gas projects in Canada through more than 200 wells and 1000 individual CoilFRAC treatments. Continuing improvements to this tool allow bypassed and marginal zones to be stimulated at nominal incremental cost. Efficient isolation and stimulation of individual sands maximized completed net pay and made zones previously considered marginal economically viable. More Experience in Canada Wildcat Hills field is located west of Calgary, Alberta, Canada, on the eastern slope of the Rocky Mountains in a protected grassland area. 6 This area has produced natural gas from deep Mississippian discoveries since During the early 1990s, two Olympia Energy wells tested shallower Viking sands. The wells initially produced about 900 Mcf/D [25,485 m 3 /d], but declined rapidly to 400 Mcf/D [11,330 m 3 /d]. Although pressure-buildup and production tests indicated substantial reserves, the low reservoir pressure, poor deliverability and high completion costs precluded development of marginal Viking zones. A 1998 seismic survey identified a third Viking target in an area where the formation was uplifted by more than 3000 ft [914 m], potentially creating natural fractures that might enhance gas deliverability. The W5M well encountered about 45 ft [14 m] of pay in five zones across 82 ft [25 m] of gross interval (next page, top). An FMI Fullbore Formation MicroImager microresistivity log verified existing natural fractures in the reservoir, but drillstem testing indicated a low pressure of 1100 psi [7.6 MPa]. Pressure-buildup tests before setting in. casing and after perforating indicated drilling-fluid invasion into natural fractures and additional formation damage from completion fluids. A mud-solvent treatment failed to remove the damage, so a fracturing treatment was selected 6. Marsh J, Zemlak WM and Pipchuk P: Economic Fracturing of Bypassed Pay: A Direct Comparison of Conventional and Coiled Tubing Placement Techniques, paper SPE 60313, presented at the SPE Rocky Mountain Regional/Low Permeability Reservoirs Symposium, Denver, Colorado, USA, March 12-15, > Coiled tubing isolation tools. The first CoilFRAC operations used a single tension-set packer above a zone with sand plugs or bridge plugs to isolate below the zone (left). Subsequent versions were modified to include an upper elastomer seal cup above the zone and a lower packer to isolate below (middle). This second-generation tool was followed by a straddle design with elastomer seal cups on the top and bottom of a ported spacer, which increased the speed of packer moves, and reduced execution time as well as operational costs (right). These specialty tools eliminated rig and wireline operations because sand plugs and bridge plugs were not needed. Coiled tubing could be moved quickly from one zone to the next without pulling out of the well. to increase gas deliverability. Fracturing down casing with limited-entry diversion was not an option because the well had already been perforated. The operator evaluated diversion with ball sealers as well as mechanical zonal isolation with sand plugs, bridge plugs or coiled tubing. Ball-sealer effectiveness is questionable, especially during fracturing treatments, so mechanical diversion was deemed the most reliable method to ensure stimulation of all pay zones. With only 13 to 16 ft [4 to 5 m] between four zones, engineers eliminated use of sand plugs because close spacing made it difficult to accurately place the correct sand volumes. Conventional jointed tubing with packers and bridge plugs for isolation involved separate operations to treat individual zones one at a time from the bottom up. This required repeated equipment mobilization and demobilization, redundant services for each zone and retrieving or moving bridge plugs after each treatment all of these made the costs prohibitive. 66 Oilfield Review

8 > Well W5M, Wildcat Hills field. Previous attempts to stimulate the Viking formation as a continuous interval were not successful because of difficulty in intersecting multiple zones with conventional single-stage fracture treatments. Closely spaced perforated intervals prohibited isolation with a packer and sand or bridge plugs. Selective CoilFRAC treatment placement simulated four zones individually to increase recovery by isolating and fracturing pay that often is bypassed or left untreated. Secondary goals were to simplify several days of completion operations into a single day and reduce cost. > Comparison of conventional and CoilFRAC Viking completions. Coiled tubing-conveyed fracture stimulations required 58% less total proppant, reduced overall completion operations from 19 days to 4, and improved well cleanup and fracturing fluid recovery. CoilFRAC treatment placement and simultaneous flowback improved fluid recovery and saved Olympia Energy about $300,000 per well in the Wildcat Hills field, which reduced cost per Mcf/D by about 78%. The operator selected CoilFRAC services to stimulate each zone separately and treat several zones in a single day. On the first day, the jointed tubing string used to perform production tests and the solvent treatment was pulled from the well. Coiled tubing, fracturing and testing equipment was moved to location on the second day while a wireline unit set a bridge plug to isolate the lower Viking formation. The maximum recommended interval that the isolation tool could straddle at that time was 12 ft [3.7 m], which was less than the length of the lowest interval, so a tension-set packer was used to fracture the first zone. Three fracture stimulations were attempted on the third day. Sticking problems required the straddle-isolation tool to be pulled for repair of the elastomer seal cups. A casing scraper run smoothed the rough casing. This step is now performed routinely before CoilFRAC treatments as part of wellbore preparation. Annulus pressure increased while pumping pad fluids in the second interval, indicating possible communication behind pipe or fracturing into an adjacent zone. This treatment was cancelled before initiating proppant, and the tool was moved to the third interval. After the fourth interval was stimulated, the straddle-isolation tool was pulled, so that openended coiled tubing could be used to clean out sand and unload fluids. On the fourth day, a snubbing unit ran jointed production tubing in the well under pressure to avoid formation damage from completion-fluid invasion. To eliminate the snubbing unit, coiled tubing now is used to run a packer with an isolation plug. After the packer is set, coiled tubing is released and removed from the well. The packer plug controls reservoir pressure until jointed production tubing is run. A slickline unit then retrieves the isolation plug, initiating well flow. Before stimulation, the W5M well flowed 3.5 MMcf/D [99,120 m 3 /d] of gas at 350-psi [2.4-MPa] surface pressure. After three of the upper four zones were fractured successfully, the well produced 6 MMcf/D [171,818 m 3 /d] at 350 psi. The well continued to produce at 5 MMcf/D [143,182 m 3 /d] and 450 psi [3.1 MPa] for several months. The CoilFRAC treatment delivered an economic production gain in addition to reducing cleanup time and simplifying completion operations (left). Minimal operations and faster cleanup helped bring production on line sooner by reducing completion cycle time from 19 to 4 days. Autumn

9 Olympia Energy drilled six more wells in the Wildcat Hills field after completion of the W5M well. Because the Viking formation varies from well to well, the operator selected fracturing techniques based on sand thickness, fracture containment barriers, vertical spacing between sands and required number of treatments. Three of these wells contained two or three thick Viking sands that were fractured down casing. The larger zones required higher pump rates to optimize fracture height and length, which ruled out use of coiled tubing because of potentially excessive surface treating pressures. Like the W5M well, the other three wells had similar interbedded sand-shale sequences and 6- to 13-ft [2- to 4-m] pay zones, so Olympia Energy used CoilFRAC selective stimulations. This approach increased productivity and recovery by selectively treating pay that had been bypassed or not stimulated effectively, and it ultimately decreased operational costs. Pre- and post-treatment production logs were run on the W5M well to evaluate increased production from zones in one of the wells that was fractured using coiled tubing (below). Prior to fracturing, the well produced 2 MMcf/d [57,300 m 3 /d] with flow from two intervals. After CoilFRAC treatments on five intervals, gas production increased to 4.5 MMcf/D [128,900 m 3 /d] with flow from four of the five intervals. Olympia Energy saved $300,000 per well on fracturing operations alone by using CoilFRAC techniques to stimulate Wildcat Hills Viking wells. One of the original Viking gas wells has been reevaluated and identified as a candidate for stimulation with coiled tubing. At a depth of 8200 ft [2500 m], this coiled tubing-conveyed application demonstrated the impact of combining coiled tubing and stimulation technologies on well productivity and reserve recovery. The smaller surface footprint, less time on location and fewer wellsite visits combined with less gas emissions and flaring as a result of flowing, testing and cleaning up all the pay zones at one time make CoilFRAC treatments particularly attractive in environmentally sensitive areas like the grasslands around Wildcat Hills field. > Pre- (left) and post-stimulation (right) evaluation. Production log spinner surveys in Viking Well W5M confirmed that CoilFRAC selective fracturing treatments in each Viking sand improved the production profile and total gas rate (right). Fracturing Designs and Operations Coiled tubing-conveyed fracturing is constrained by restrictions on fluid and proppant volumes related primarily to smaller tubular sizes and pressure limitations. The application of CoilFRAC services requires alternative fracture designs, specialized fluids, high-pressure coiled tubing equipment, and integrated fracturing and coiled tubing service teams to ensure effective stimulations and safe operations. 7 Injection rates, fluid parameters, treatment volumes, in-situ stresses and formation characteristics determine the net pressure available downhole to create a specific fracture geometry width, height and length. Minimum pump rates are required to generate the desired fracture height and to transport proppant along the length of a fracture. Minimum proppant concentrations are needed to attain adequate fracture conductivity. Coiled tubing strings have a smaller internal diameter (ID) than the standard jointed workstrings used in conventional fracturing operations. At the injection rates required for hydraulic fracturing, frictional pressure losses associated with proppant-laden slurries can lead to high treating pressures that exceed surface equipment and coiled tubing safety limits. Using larger coiled tubing reduces friction pressures, but increases equipment, logistics and maintenance costs, and may not be practical for small-diameter slimhole and monobore wells. This means that treatment rates and proppant volumes for coiled tubing-conveyed fracturing must be reduced compared with those of conventional fracturing. The challenge is to achieve injection rates and proppant concentrations that transport proppant effectively and create the required fracture geometry. Coiled tubing-conveyed fracturing requires alternative equipment and treatment designs to ensure acceptable surface treating pressures without compromising stimulation results. Reservoir characterization is the key to any successful stimulation treatment. Like conventional fracturing jobs, coiled tubing treatments must generate a fracture geometry consistent with optimal reservoir stimulation. The preferred approach is to design CoilFRAC pumping schedules that balance required injection rates and optimal proppant concentrations with coiled tubing treating-pressure constraints. Fracturing fluid selection depends on reservoir characteristics and fluid leakoff, downhole conditions, required fracture geometry and proppant transport. Fluids 68 Oilfield Review

10 for CoilFRAC treatments include water-base linear or low-polymer systems and polymer-free ClearFRAC viscoelastic surfactant (VES) fluids. 8 In the past, polymers provided fluid viscosity to transport proppant. However, residue from these fluids can damage proppant packs and reduce retained permeability. Engineers often increase proppant volumes to compensate for any reduced fracture conductivity, but slurry friction increases exponentially with higher proppant concentrations and can limit the effectiveness of CoilFRAC treatments. Increased surface treating pressure from frictional pressure losses is the dominant factor in coiled tubing-conveyed fracturing, so reducing surface pump pressures is critical in CoilFRAC applications, particularly in deeper reservoirs. Because of their unique molecular structure, VES fluids exhibit as much as two-thirds lower frictional pressures than polymer fluids (right). Nondamaging ClearFRAC fluids may provide adequate fracture conductivity with lower proppant concentrations at acceptable surface treating pressures. This facilitates optimized fracture designs. These fluid characteristics make coiled tubing-conveyed fracturing feasible at commonly encountered well depths. Another advantage of ClearFRAC fluids is reduced sensitivity of fracture geometry to fluid injection rate. Height growth is better contained, resulting in longer effective fracture lengths, which is particularly important when treating thin, closely spaced zones. Fluids based on a VES also are less sensitive at downhole temperatures and conditions that cause fracturing fluids to break prematurely. If pumping stops because of an operational problem or fracture screenout, the stable suspension and transport characteristics of ClearFRAC fluids prevent proppants from settling too quickly, especially between the seal cups of straddle-isolation tools. This allows time to clean out remaining proppant and decreases the risk of stuck pipe. In addition, these fluids provide a backup contingency in high-risk environments, such as highangle or horizontal wells, where proppant settling also can be a problem. Recovering treatment fluids is critical when target zones have low permeability or low bottomhole pressure. Another benefit of VES fracturing fluids is more effective post-stimulation cleanup. Field experience has shown that VES fluids break down completely in contact with reservoir hydrocarbons, through extended dilution by formation water or under prolonged exposure to reservoir temperature, and are transported easily into wellbores by produced fluids. Retained permeability is close to 100% of > Effect of friction-reducing fluids. As CoilFRAC applications expand to include deeper wells, low-friction fluids will be a key to future success. This plot compares surface-treating pressure versus depth for 2-in. coiled tubing using a polymer-based fracturing fluid and a ClearFRAC viscoelastic surfactant (VES) fluid, both with 4 ppa proppant concentrations. original permeability with VES fluids. In addition, treating and flowing back all the zones at one time improve fluid recovery and fracture cleanup. High-strength, to in. coiled tubing is used to accommodate higher injection pressures. Coiled tubing for fracturing operations is fabricated from high yield-strength, premium-grade steels with high burst pressure. For example, in., 90,000-psi [621-MPa] yield strength coiled tubing has a burst-pressure rating of 20,700 psi [143 MPa] and can withstand collapse pressures of 18,700 psi [129 MPa]. Coiled tubing is hydrostatically tested to about 80% of its burst-pressure rating, 16,700 psi [115 MPa] for this in. string prior to pumping operations, and maximum pump pressure is set at 60% of the design burst pressure, or about 12,500 psi [86 MPa], for this example. Because the entire coiled tubing string contributes to friction pressure, regardless of how much is inserted in a well, the length of coiled tubing on a reel should be minimized relative to the deepest interval. There has been concern that centrifugal forces on the proppant would erode the inner wall of spooled coiled tubing. However, visual and ultrasonic inspection before and after fracturing found no erosion inside the coiled tubing and detected only minor erosion at coiled tubing connectors after pumping as many as nine treatments. Operational safety is critical at the high pressures required for hydraulic fracturing treatments. For example, personnel should not be permitted near wellheads or coiled tubing equipment during pumping operations. Coiled tubingconveyed fracturing requires specialized surface equipment and innovative modifications to ensure safe operations and to deal with contingencies in the event of a screenout. 9 On the surface, coiled tubing equipment, such as quickresponse, gas-operated relief valves, remotely operated fracturing manifolds and modifications to coiled tubing reels and manifolds, allow highrate pumping of abrasive slurries. Precise depth control also is important for selective stimulations. Inaccurate positioning of coiled tubing results in serious and costly problems perforating off-depth, placing a sand plug in the wrong place, problems positioning straddleisolation tools or stimulating the wrong zone. Straddle-isolation tools must be positioned accurately across perforated intervals. Five types of depth measurements are used: standard levelwind pipe measurements as coiled tubing comes off the reel, a depth-monitoring system in the injector head, mechanical casing-collar locators and two new independent systems used by Schlumberger the Universal Tubing-Length Monitor (UTLM) surface measurement and the DepthLOG downhole casing-collar locator. 7. Olejniczak SJ, Swaren JA, Gulrajani SN and Olmstead CC: Fracturing Bypassed Pay in Tubingless Completions, paper SPE 56467, presented at the SPE Annual Technical Conference and Exhibition, Houston, Texas, USA, October 3-6, Gulrajani SN and Olmstead CC: Coiled Tubing Conveyed Fracture Treatments: Evolution, Methodology and Field Application, paper SPE 57432, presented at the SPE Eastern Regional Meeting, Charleston, West Virginia, USA, October 20-22, Chase B, Chmilowski W, Marcinew R, Mitchell C, Dang Y, Krauss K, Nelson E, Lantz T, Parham C and Plummer J: Clear Fracturing Fluids for Increased Well Productivity, Oilfield Review 9, no. 3 (Autumn 1997): A screenout is caused by proppant bridging in the fracture, which halts fluid entry and fracture propagation. If a screenout occurs early in a treatment, pumping pressure may become too high and the job may be terminated before an optimal fracture can be created. Autumn

11 In the past, the accuracy of standard coiled tubing depth measurements was about 30 ft [9.1 m] per 10,000 ft [3048 m] under the best conditions and as much as 200 ft [61 m] per 10,000 ft in the worst cases. The dual-wheel UTLM surface measurement is self-aligning on the coiled tubing, minimizes slippage, offers improved wear resistance and measures unstretched pipe (below). 10 Two measuring wheels constructed of wear-resistant materials, on-site data processing and routine calibration eliminate the effects of wheel wear on surface measurement repeatability and provide automatic redundancy in addition to slippage detection. The remaining factors that affect measurement accuracy and reliability are contaminants and buildup on wheel surfaces, and thermal effects that change wheel dimensions. An antibuildup system prevents contamination of wheel surfaces. Downhole coiled tubing pipe deformation is evaluated using computer simulation. For thermal pipe deformation modeling, a wellbore simulator provides a temperature profile. The total deformation can be estimated with an accuracy of about 5 ft [1.5 m] per 10,000 ft. The combination of more accurate surface measurements with modeling and improved operational procedures result in about a 11 ft [3.4 m] per 10,000 ft accuracy, and a repeatability of about 4 ft [1.2 m]. In most cases, a value of less than 2 ft [0.6 m] is achieved. > The UTLM dual-wheel surface depthmeasurement device. > Hiawatha field producing horizons. In the Hiawatha field of northwest Colorado (insert), pay zones historically were grouped in intervals, or stages, of 150 to 200 ft [46 to 61 m] and stimulated with a single fracture treatment. Thin sands were grouped with thick sands, and occasionally thin sands were bypassed to avoid less effective stimulation of more prolific sands. Multiple hydraulic fracture stages were still required to treat the entire wellbore. Each fracture stage was isolated with a sand plug or mechanical bridge plug. Justifying completion of thin sands capable of 100 to 200 Mcf/D [2832 to 5663 m 3 /d] was difficult. 70 Oilfield Review

12 Previously, depth correction with wireline inside coiled tubing or memory gamma ray logging tools, flags painted directly on the coiled tubing and mechanical casing-collar locators often were inaccurate, costly and time-consuming. Schlumberger now uses a wireless DepthLOG tool, which detects magnetic variations at joint casing collars as tools are run into a well and sends a signal to surface through changes in hydraulic pressure. Subsurface depths are determined quickly and accurately by comparison with baseline gamma ray correlation logs. The use of wireless technology decreases the number of coiled tubing trips into a well and saves up to 12 hours per operation on typical coiled tubing-conveyed perforating and stimulation operations. In the past, separate coiled tubing services, if required, followed fracturing operations to clean out excess proppant. Coiled tubing-conveyed fracturing, however, requires the combined efforts of fracturing and coiled tubing personnel. Initially, service crews faced a steep learning curve as they began working together to reduce the time required for various operations. Subsequent CoilFRAC projects increased operational efficiency and reduced completion time. To further increase efficiency, Schlumberger has formed dedicated CoilFRAC teams to integrate coiled tubing and fracturing expertise. Revitalizing a Mature Field Texaco Exploration and Production Inc. (TEPI), now a ChevronTexaco company, extended the productive life of West Hiawatha field in Moffat county, Colorado, USA, with CoilFRAC techniques. 11 Discovered in the 1930s, this field has 18 pay sands over 3500 ft [1067 m] of gross interval. Gas production comes from the Wasatch, Fort Union, Fox Hills, Lewis and Mesaverde formations (previous page, right). Previously, wells were completed with , 5- or 7-in. casing and stimulated using conventional staged fracturing treatments. A common practice was to stimulate zones from the bottom upward until production rates were satisfactory. As a result, thin zones often were ignored and undeveloped uphole potential existed throughout the field. In 1999, TEPI evaluated bypassed pay in the field to identify and rank workover potential based on reservoir quality, cement integrity, completion age and wellbore integrity. New drilling locations were identified after a successful workover on Duncan Unit 1 Well 3, but the challenge was to develop a strategy that could effectively stimulate all of the pay zones during initial completion operations. > Evaluating single-stage Hiawatha field fracture stimulations. Without selective isolation of individual sands, variations in fracture gradients make it difficult to optimize fracture lengths with a single conventional treatment and limited-entry perforating. For two Wasatch zones that would be grouped when stimulating multiple intervals with a single treatment, StimCADE hydraulic fracturing simulator plots indicate that about two-thirds of the proppant is placed in the upper interval (top). This results in a wider, more conductive fracture and a half-length almost 50% greater than in the lower interval (bottom). If there are more than two zones, this problem is further compounded by variations in discontinuous sands from wellbore to wellbore. The operator chose CoilFRAC services to selectively stimulate Wasatch and Fort Union sands, which comprise multiple sands from 5 to 60 ft [1.5 to 18 m] thick from 2000 to 4000 ft [600 to 1200 m] deep. This approach provided flexibility to design optimal fracture treatments for each zone rather than large jobs to intersect multiple zones over longer intervals. In the first drill well, individual CoilFRAC treatments were performed on 13 zones in three days. Seven zones were treated in a single day. This well s average first month production was 2.3 MMcf/D [65,900 m 3 /d]. The second drill well involved eight treatments in one day. Average production from the second well during the first month was 2 MMcf/D. Treating pressures ranged from 3200 psi [22 MPa] to the maximum allowable 7000 psi [48 MPa]. Zones separated by 10 to 15 ft [3 to 4.6 m] were fractured with no communication between stages. Pump-in tests verified that fracture gradients between zones varied from 0.73 to 1 psi/ft [16.5 to 22.6 kpa/m]. The variation in fracture gradient for each zone confirmed the difficulty of stimulating multiple zones with conventional stage treatments (above). In addition to eight workovers with mixed success, nine successful 10. Pessin JL and Boyle BW: Accuracy and Reliability of Coiled Tubing Depth Measurement, paper SPE 38422, presented at the 2nd North American Coiled Tubing Roundtable, Montgomery, Texas, USA, April 1-3, DeWitt M, Peonio J, Hall S and Dickinson R: Revitalization of West Hiawatha Field Using Coiled- Tubing Technology, paper SPE 71656, presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, USA, September 30-October 3, Autumn

13 wells were drilled in Hiawatha field from May 2000 through July These new wells were completed with CoilFRAC stimulations in the Wasatch and Fort Union formations, and conventional fracture treatments for the more continuous Fox Hills, Lewis and Mesaverde intervals below 4000 ft [1220 m]. To quantify coiled tubing stimulation results, the CoilFRAC completions were compared with wells fractured conventionally between 1992 and 1996 (right). Average production from CoilFRAC completions increased 787 Mcf/D [22,500 m 3 /d], or 114%, above historical rates. However, production from individual wells may be misleading if reserves are drained from offset wells. Field output will not increase as expected when there is interference between wells; natural pressure depletion should result in new wells producing less, not more. From 1993 to 1996, Hiawatha field output increased from 7 to 16 MMcf/D [200,500 to 460,000 m 3 /d] as a result of the 12-well drilling program. Production doubled again from 11 to 22 MMcf/D [315,000 to 630,000 m 3 /d] as a result of workovers and new wells completed mostly with coiled tubing-conveyed stimulations. Field production is at the highest level in 80 years. Stimulating each zone individually during initial completion operations is believed to be the key to improving production and increasing reserve recovery in this mature field. State-of-the-Art Downhole Tools Isolation tools have evolved along with CoilFRAC treatments and specific requirements generated by various stimulation applications. Coiled tubingconveyed fracturing operations are performed under the most dynamic reservoir stimulation conditions. Treatments take place in live wells at formation temperatures and pressures, and with the completion of each selective stimulation, these conditions change. As a result, increasingly demanding applications in deeper wells require more reliable, multiple-set isolation tools. Driven by a need to minimize operational and financial risks and reduce the impact of unplanned events, like proppant screenout, Schlumberger developed the CoilFRAC Mojave line of downhole tools (next page). This improved straddle system consists of three technologies the pressure-balanced disconnect, the modular straddle assembly with ported sub, and the slurry dump valve. In combination, these components provide selective placement of sequential acid or proppant fracture stimulations, and matrix acid, > Analyzing Hiawatha field coiled tubing fracturing results. Production from wells completed with CoilFRAC selective isolation and simulation treatments (red) was compared with production from wells that were previously fractured conventionally (black). Average daily well rates for each month was normalized to time zero and plotted for the first six months. Initial production from the CoilFRAC completions was about 787 Mcf/D [22,500 m 3 /d], or 114%, more than historical rates. screenless sand-control or scale-inhibitor treatments in a single trip with coiled tubing. The pressure-balanced disconnect features a mechanical shear disconnect that is pressurebalanced to coiled tubing treating pressure. Only mechanical coiled tubing loads are transferred to the shear-release pins; treating pressure does not affect the shear-pin release function. This reduces the likelihood of leaving the tool in a well as a result of unexpectedly high downhole treating pressures during CoilFRAC stimulations, such as a screenout. The pressure-balanced disconnect allows coiled tubing to be run deep because the disconnect does not require extra shear pins to account for pressure loads during treatments. If the tool becomes stuck, it can be fished by overshot or internal fishing neck. The CoilFRAC Mojave isolation tool has opposing elastomer cups for to 7-in. casing. The tool functions in vertical or horizontal wells and has no mechanical slips and no moving parts. An internal fluid bypass in the tool body permits running to deeper depth 10,000 ft instead of less than 4000 ft. This feature lightens coiled tubing loads during trips in and out of wells to reduce elastomer wear, minimize swab and surge forces on formations and decrease the risk of a tool sticking between zones. A modular design and special 2-ft [0.6-m] ported fracturing sub allow 4-ft sections to be assembled for spacing elastomer cups up to 30 ft apart. The CoilFRAC fracturing sub also includes a fluid bypass and resists erosion when pumping up to 300,000 lbm [136,100 kg] of sand. It is possible to pump up to 500,000 lbm [226,800 kg] of less erosive resin-coated and man-made ceramic proppants. Reverse circulation is required to clean the coiled tubing and CoilFRAC Mojave isolation tool when run without a slurry dump valve. A lower reversed bottom cup seals during reverse circulation to improve post-treatment cleanup. A gauge port is built into the tool for downhole pressure and temperature measurements. Since the slurry dump valve (SDV) is flowoperated, no coiled tubing movement is required. One SDV design in two sizes is compatible with standard to 7-in. CoilFRAC Mojave tools and functions in vertical or horizontal wells. Incorporating a SDV allows slurry to be dumped from the coiled tubing between zones and facilitates stimulations in low-pressure reservoirs and formations with fracture gradients of less than a full water gradient, or 0.4 psi/ft [9 kpa/m]. The SDV is closed and acts as a fill valve when running in a well. It also reduces formation damage during multizone well treatments. Reverse circulation is not required for coiled tubing cleanup, which reduces total stimulation fluid requirements, eliminates the environmental impact of slurry returned to surface, reduces elastomer wear by equalizing pressure across elastomer seal cups, and reduces abrasive wear on coiled tubing and surface equipment. 72 Oilfield Review

14 > CoilFRAC Mojave isolation tools. From single mechanical packers to elastomer cup and packer combinations and the earliest versions of opposing elastomer-cup straddle tools, the suite of CoilFRAC tools has expanded to include specially designed straddle assemblies. The effectiveness of CoilFRAC straddle assemblies for zonal isolation has been aided by more reliable sealing technologies. An annular flow path within the assembly allows for easy deployment and retrieval. 12. Al-Qarni AO, Ault B, Heckman R, McClure S, Denoo S, Rowe W, Fairhurst D, Kaiser B, Logan D, McNally AC, Norville MA, Seim MR and Ramsey L: From Reservoir Specifics to Stimulation Solutions, Oilfield Review 12, no. 4 (Winter 2000/2001): NODAL analysis couples the capability of a reservoir to produce fluids into a wellbore with tubular capacity to conduct flow to surface. The technique name reflects discrete locations nodes where independent equations describe inflow and outflow by relating pressure losses and fluid rates from outer reservoir boundaries across the completion face, up production tubing and through surface facility piping to stock tanks. This method allows calculation of rates that wells are capable of delivering and helps determine the effects of damage, or skin, perforations, stimulations, wellhead or separator pressure and tubular or choke sizes. Future production also can be estimated based on anticipated reservoir and well parameters. Optimizing Recovery in South Texas Samedan Oil Corporation operates North Rincon field in south Texas, producing gas from various zones of the Vicksburg formation at 6000 to 7000 ft [1800 to 2100 m]. The Martinez B54 well, completed in a single 25-ft [7.6-m] zone, had an initial production rate of 4.5 MMcf/D before declining to 1 MMcf/D. In December 2000, Samedan evaluated fracturing this zone for the first time as well as completing deeper pay in the Martinez B54 well. Openhole logs had identified several other productive zones that had been intentionally bypassed because of marginal economics. In February 2001, Schlumberger assembled a multidisciplinary team to integrate petrophysical and reservoir knowledge with completion design, execution and evaluation services using the PowerSTIM stimulation optimization initiative. 12 Samedan and the PowerSTIM team analyzed well data to determine reservoir size and remaining reserves for the current producing zone. These calculations indicated a 19-acre [7700-m 2 ] drainage area and confirmed that a nearby geologic unconformity acted as a seal. Production and NODAL analyses matched the 1-MMcf/D production and indicated that, based on a limited drainage area and low formation damage, remaining reserves could be recovered in a few months. 13 This interval was not a candidate for stimulation. Samedan decided to deplete the existing zone before completing the most attractive bypassed zones. Reinterpreted logs indicated 77 ft [23 m] of high-quality net pay with significant recoverable reserves in five deeper zones over 700 ft [213 m] of gross interval. Conventional stimulation techniques required limited-entry perforating for diversion of large fluid and proppant volumes pumped at high rates to cover and fracture this entire interval. The operator considered setting production tubing and a packer below existing perforations and completing only one or two of the uppermost bypassed zones. This approach, however, would leave a significant volume of additional reserves untapped behind pipe. The PowerSTIM team recommended CoilFRAC selective isolation services with optimized fracture designs to complete and individually stimulate all five bypassed zones. A 2-in. coiled tubing string was selected to convey fracturing fluids and proppant at the required rates. An SCMT Slim Cement Mapping Tool log confirmed cement integrity and adequate zonal isolation behind pipe across the proposed completion intervals. The existing perforations were sealed with a cement squeeze prior to CoilFRAC operations. Autumn

15 < Martinez B54 well CoilFRAC treatment stimulation results for five zones. In May 2001, Samedan and Schlumberger performed a five-stage CoilFRAC selective stimulation (next page, top). On the first day, the five zones were perforated with deep-penetrating PowerJet premium charges to maximize perforation entry-hole size and reservoir penetration. After perforating, the commingled zones produced 1.1 MMcf/D [31,500 m 3 /d] during a prestimulation test. On the second day, each zone was isolated sequentially with a 5-in. CoilFRAC Mojave straddle tool and fracture-stimulated with a nondamaging ClearFRAC fluid and 136,000 lbm [61,700 kg] of man-made ceramic proppant. All five zones were treated within a 24-hour period. Pump rates ranged from 8 to 10 bbl/min [1.3 to 1.6 m 3 /min] with treating pressures up to 11,000 psi [76 MPa]. Because of potentially high gas production rates, PropNET fiber additives were incorporated at the end of the pumping schedules to prevent proppant flowback. 14 When all the zones were commingled and tested, the well flowed more than 5.1 MMcf/D [146,000 m 3 /d] and 120 B/D [19 m 3 /d] of condensate, which closely matched production predictions. A production log spinner survey indicated that four of the five Vicksburg zones had been stimulated successfully (above and left). One month later, the well was still producing about 5 Mcf/D, which did not follow the expected decline. Estimated payout was three months. Samedan engineers evaluated the next three drill wells, but none of these new wells were viable candidates for coiled tubing-conveyed fracture stimulation. Completing five zones in a single trip mitigated the risk of formation damage from multiple well interventions, and risk of fluid swabbing associated with conventional fracturing operations, jointed tubing and standard downhole tools. This CoilFRAC treatment took only two days, while a conventional five-stage fracturing job might have taken up to two weeks. 74 Oilfield Review

16 Accurate CoilFRAC selective placement allows scale inhibitors to be conveyed deeper into the formation during fracturing or acidizing stimulation treatments. Integrating scale inhibitors and stimulation treatment fluids into a single step ensures that the entire productive interval including the proppant pack is treated. Performing multiple, smaller fracture treatments is another approach to reduce scale buildup and sand production. This method reduces the pressure drop across the formation face, which decreases or, in some cases, prevents scale and asphaltene formation. During production, pressure drawdown increases the vertical stress on producing intervals and exacerbates sand production. An alternative is to treat smaller intervals and reduce the pressure drop across the formation face. > Martinez B54 well in the North Rincon field, south Texas (Courtesy of Samedan Oil Corporation). > Unconventional coiled tubing-conveyed treatments. CoilFRAC treatments also are applicable for chemical scale inhibition and sand-control methods. Coiled tubing places scale inhibitors included in a preflush before fracturing or proppant impregnated with scale inhibitors more effectively than conventional treatment techniques (left). Novel screenless completions provide sand control without downhole mechanical screens and gravel packing by using technology like resin-coated proppants and PropNET fibers to control proppant flowback and sand production (right). The primary challenge of applying these techniques is ensuring coverage of all perforated pay zones. Additional Applications The combination of reservoir-stimulation and well-treatment technologies with coiled tubing conveyance is expanding selective CoilFRAC techniques to include applications, like acid fracturing, and specialized completion techniques such as scale inhibition, controlling proppant flowback and screenless sand control (above). With advances in friction-reducing fluids, injection rates are sufficient for coiled tubing and CoilFRAC tools to be used as mechanical diversion during acid fracturing. This capability is increasingly important in mature carbonate reservoirs when small zones within larger producing intervals require stimulation. CoilFRAC stimulations help operators deplete reserves uniformly across an entire hydrocarbon-bearing interval and facilitate reservoir management. The downhole buildup of scales, asphaltenes or migrating fines and the plugging of perforations and completion equipment impair permeability and can restrict or prevent production altogether. Screenless Sand-Control Completions Innovative screenless completions provide sand control without the need for downhole mechanical screens and gravel packing by using technologies such as resin-coated proppants and PropNET fibers to control proppant flowback and sand production. The primary challenge of applying screenless technology is ensuring coverage of all perforated pay zones. In general, interval length is the controlling factor. Thicker intervals typically reduce treatment success rates. Coiled tubing-conveyed fracturing, with the capability of treating numerous zones, increases screenless completion effectiveness and reduces overall costs while increasing net pay potential. Treatments in North America have reduced proppant flowback by five-fold. PT. Caltex Pacific Indonesia, a ChevronTexaco affiliate, operates the Duri field in the Central Sumatra basin. 15 Primary recovery is low, so steam injection is used to achieve higher recovery factors. This multibillion-barrel steamflood covers 35,000 acres [14 million m 2 ] and produces 280,000 B/D [44,500 m 3 /d] of high-viscosity crude oil. Oil-bearing sands are highly unconsolidated, Miocene-age formations with permeability 14. Armstrong K, Card R, Navarrete R, Nelson E, Nimerick K, Samuelson M, Collins J, Dumont G, Priaro M, Wasylycia N and Slusher G: Advanced Fracturing Fluids Improve Well Economics, Oilfield Review 7, no. 3 (Autumn 1995): Kesumah S, Lee W and Marmin N: Startup of Screenless Sand Control Coiled Tubing Fracturing in Shallow, Unconsolidated Steamflooded Reservoir, paper SPE 74848, prepared for presentation at the SPE/ICOTA Coiled Tubing Conference and Exhibition, Houston, Texas, USA, April 9-10, Autumn

17 as high as 4000 md (right). Combined pay thickness is about 140 ft [43 m] over an interval from X430 to X700 ft. In addition to 3600 producing wells, the operator maintains about 1600 steaminjection and temperature-observation wells. Heat requirements are lower in temperaturemature areas where the steamflood has been in operation for an extended period of time. Steam injection can be reduced, allowing the operator to convert injectors and observation wells into producers. Low reservoir pressure causes drilling, completion and production problems including lost circulation, hole collapse and sand production. Severe sanding leads to frequent well servicing to replace worn or stuck artificiallift equipment. The marginal nature of these wells, initially completed with 4-, 7-, or in. OD monobore casing, limits conventional gravelpacked screens for sand control. In most wells, screens are not installed because of restricted wellbore access, smaller pump sizes and, consequently, unfavorable production rates. In a recent field test on several wells, the operator in Duri field used CoilFRAC techniques to perform screenless completions using curable resin-coated sand and tip-screenout fracture designs to prevent proppant flowback and migration of formation grains. 16 After resin-coated sand is placed and cured, proppant packs are locked in place to create a stable filter against the formation in perforation tunnels and nearwellbore regions. Using resin-coated proppant to control sand without mechanical screens is not new. In 1995, a Duri field pilot project used conventional fracturing with resin-coated sand to complete Rindu sands at about X450 ft. Single-stage tip-screenout treatments attempted to place resin-coated proppant in multiple zones across 50 to 100 ft [15 to 30 m] of gross interval. This technique failed to achieve acceptable results because the gross intervals were too long and not all perforations received resin-coated sand. In addition, produced formation sand covered some lower zones and steam injection did not cure the resin-coated sand across the entire section. The primary objectives of the most recent field test were to ensure complete treatment coverage of all perforations and achieve tipscreenout fractures for proper proppant packing. Grain-to-grain contact and closure stress improve the curing process and ensure a strong compacted filter medium. Heat or alcohol-base fluids cure phenolic resins. The operator uses both methods to ensure a complete resin set. CoilFRAC selective isolation and treatment placement provided accurate and complete perforation coverage, which made screenless completions a viable alternative to gravel > Duri field, Indonesia, producing horizons and typical well completion. packing or frac packing with screens, and previous screenless completions that were attempted conventionally. Fracture treatments and pumping schedules were designed to achieve required fracture halflength and conductivity. Relatively low pumping rates control vertical coverage, while higher proppant concentrations are needed to ensure fracture conductivity and achieve tip screenout. The maximum rate is usually about 6 bbl/min [1 m 3 /min] with proppant concentrations of 8 pounds of proppant added (ppa). The number of treatment stages in a given well was determined by evaluating perforated interval length and spacing between zones. Interval length needed to be less than 25 ft to ensure complete coverage with a minimum of 7 ft [2 m] between intervals to allow the isolation tool to set properly. The operator verified cement bond and quality to ensure isolation behind the pipe and avoid proppant channeling. Extra resincoated sand deposited after each treatment isolated that interval from subsequent treatment intervals. After all zones were treated, the operator left the well undisturbed for about 12 hours to allow the resin to set and obtain adequate strength. Partially cured resin-coated sand in the wellbore was drilled out prior to production. With the exception of one well, screenless completions significantly increased cumulative oil production during nine months of evaluation (next page, left). Average failure frequency before CoilFRAC screenless completions was 0.5 per well per month. The operator allocated 36 rig days and 32,000 bbl [5080 m 3 ] of deferred oil production for all four wells to clean out sand. After CoilFRAC screenless treatments were performed, failure frequency dropped to 0.14 per well per month, resulting in an extra five months of oil production per well per year. Screenless 16. In standard fracturing, the fracture tip is the final area to be packed with proppant. A tip-screenout design causes proppant to pack, or bridge, near the end of the fractures in early stages of a treatment. As additional proppant-laden fluid is pumped, the fractures can no longer propagate deeper into a formation and begin to widen or balloon. This technique creates a wider, more conductive pathway as proppant is packed back toward the wellbore. 76 Oilfield Review

18 > Ongoing CoilFRAC operations in Medicine Hat, Alberta, Canada. > CoilFRAC screenless completion results in Duri field, Indonesia. CoilFRAC treatments paid out in 35 to 59 days. However, the use of resin-coated sand in extremely hot steamflood conditions was found to have limitations. Early in the application of screenless completions, the operator recognized a need to use inert proppant flowback control. The resin coating used initially in CoilFRAC screenless completions was thermally stable to 375 F [191 C], but could fail in steam environments of 400 F [204 C]. As a result, periodic steam injection and flowback to stimulate oil output could cause stress cycling and proppant-pack failure that resulted in sand production. Proppant flowback control using PropNET fibers rated to 450 F [232 C] is proving to be a solution to this problem. The operator selected a local sand combined with PropNET fibers in place of resin-coated sand for eight recent screenless completions in Duri field. The PropNET fibers were added throughout sand-laden treatment stages to ensure complete interval coverage. Optimized perforating techniques also has been introduced for screenless sand control. These wells have minimal production data, but early production results are encouraging. Milestones in Selective Stimulations Selective coiled tubing-conveyed isolation and stimulation have established a template for future workovers on existing wells and new well completions. The CoilFRAC methodology allows controlled delivery and accurate placement of treatment fluids and proppant in existing or bypassed pay intervals at little or no additional cost because decreased fluid volumes and elimination of redundant operations reduce mobilization, equipment and material charges. CoilFRAC treatments are useful for fracturing bypassed single or multiple zones, protection of casing and completion equipment, and for development of coalbed methane reserves. This technique is also valuable in settings where chemical inhibition, reservoir flow-conformance modifications, water-control or sand-control methods may be required. Schlumberger has pumped more than 12,000 CoilFRAC fracture stimulations in more than 2000 wells. Coiled tubing-conveyed treatments can now be performed in vertical, high-angle and horizontal wells with measured vertical depths up to 12,200 ft [3720 m]. Pumping rates can range from 8 to 25 bbl/min [1.3 to 4 m 3 /min] with 5 to 12 ppa of proppant. Coiled tubing-conveyed fracturing was originally developed for multilayered shallow-gas reservoirs in Canada and further developed in the USA (above). These CoilFRAC treatments, however, are being refined in applications around the world, from Indonesia, Argentina and Venezuela to Mexico and now Algeria. The largest total volume of proppant placed in a single wellbore was 850,000 lbm [385,555 kg] for a well treatment in northern Mexico. A well in southeast New Mexico, USA, was the first horizontal well to be fracture stimulated using a CoilFRAC Mojave tool. Two separate zones at 9123 and 9464 ft [2781 and 2885 m] measured depth were treated. The deepest CoilFRAC job to date was recently performed at 10,990 ft [3350 m] for Sonatrach in Algeria. The progress to date in selective stimulations has been impressive. Continued research and field experience are expected to further extend the range of applications and reach of this innovative technique. MET Autumn