Fracturing/pressure pumping

A Novel Completion Method for Sequenced Fracturing in the Eagle Ford Shale

Evenly fracturing all clusters in heterogeneous zones is challenging in long horizontal sections penetrating heterogeneous reservoirs, as is often the case in the Eagle Ford shale.

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Evenly fracturing all clusters in heterogeneous zones is challenging in long horizontal sections penetrating heterogeneous reservoirs, as is often the case in the Eagle Ford shale. Furthermore, efforts to improve well economics result in reducing completion time by extending the length of each stage even farther to decrease the number of interventions required for completing the well. To address this challenge, a new sequenced-fracturing technique has been developed on the basis of a novel composite fluid comprising degradable fibers and multisized particles.

Introduction

In Eagle Ford shale completions, which typically rely on limited-entry principles, the distribution of fluid flow is a function of fracture initiation and propagation pressure, differential pressure on perforations, and net pressure of the stimulation treatment. New injection-evaluation and logging techniques demonstrated the possibility of significant variations in fracture-gradient anisotropy and formation fluid-flow distribution over the intervals of horizontal wells. Recently, several operators in the Eagle Ford play revised their completion strategy and decided to increase differential pressure on perforations by reducing the number of perforation clusters per stimulation stage. This approach requires a larger number of wireline interventions to place the additional necessary bridge plugs and is accompanied by longer subsequent coiled-tubing milling operations. A solution was needed to increase the number of perforations being stimulated without increasing the complexity of operations, the associated time, and the costs.

Increasing Contact, Not Operational Complexity

Chemical diversion has been proposed as a cost-effective and faster alternative to mechanical techniques for isolating perforations and forcing fluids into previously unstimulated portions of the reservoir. Numerous materials (e.g., benzoic acid flakes, rock salt, fracturing balls, and rubber-coated neoprene balls) are commercially available for this purpose, but none was found to provide reliable diversion.

The sequenced fracturing technique described here introduces a composite fluid that temporarily plugs zones that were previously stimulated and diverts fluids to understimulated regions. The composite fluid overcomes the limitations of traditional chemical diverters by coupling degradable particles of a wide size distribution.

The result of the composite fluid is a low-permeability plug delivered downhole at high concentration and requiring only a minimum amount of material to generate diversion. The development of the composite fluid relied on a series of laboratory experiments.

Laboratory Tests

To optimize the particle-size distribution, a laboratory setup that comprised a syringe connected to a slot with a width of 8–16 mm was used (Fig. 1). The slot was equipped with a sieve with openings smaller than the diameter of the largest particles but larger than the diameter of any other particles in the tested blends. Once the material is placed downhole, it is important that it maintain its plugging ability for the entire time required to complete a fracturing stage. Tests were conducted to verify that the solid material meets this requirement (please see the complete paper for details of these tests). In none of the experimental cases was displacement or extrusion of the polymer mass through the slot observed, which is a valid indicator of plug stability. No water leak or bypasses through the plug were observed during experiments.

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Fig. 1—Laboratory setup used to optimize particle-size distribution.

Actual testing of the composite fluid on wells showed that the material can withstand at least 3,700-psi pressure differential, generating pressure buildup inside the wellbore that is sufficient for diversion.

Finally, experiments were designed to determine the degradation kinetics of the solids entering into the composition of the composite fluid. (For details of this testing, please see the complete paper.) Results showed that, over the temperature range explored, the size of the solids did not have any significant effect on the degradation rate, because the process is driven not by surface degradation but by bulk degradation.

Design Methodology

The area of the Eagle Ford shale in which the case-study well was drilled had the following parameters: bottomhole static temperature from 269 to 300°F, a total vertical-depth average of 11,500 ft, and lateral lengths from 4,600 to 7,200 ft. The number of stages varied from 12 to 23, and plug spacing was between 300 and 400 ft. All of the wells were shot using six clusters, 1-ft guns, and 6 shots/ft for a total of 36 holes per stage. Completion time averaged 8 days per well. The fracture-stage size varied from 163,000 to 208,000 lbm of sand and used a combination of 30/50 and 20/40 proppants with an option of using a tail-in of 20/40 curable resin-coated proppant.

In a majority of wells in the area, the fracturing treatments were pumped in conjunction with a set of two or three additional wells in the same pad by means of a “zipper” operation that allowed completion of between five and eight stages in a 24-hour period. The composite fluid pumped during the sequenced-fracturing technique requires the use of a dedicated high-pressure line, a batch mixer, and a fracturing pump to deliver the diverting material to the well. A work flow process was established to avoid mixing of the diversion material with the main fracturing equipment.

The process of the sequenced-fracturing technique involved two different components, with a diversion stage consisting of the composite fluid between them. The first component was an optional acid spearhead followed by a proppant-fracturing treatment that followed a normal pump schedule and reached the normal maximum proppant concentration. The operations were usually pumped at the rate of 50 to 60 bbl/min until the final proppant stage was completed. Because of treating-line limitations, the rate was usually decreased by 5 bbl/min on the main-line pumps, and the diversion material was pumped into the treating line at high concentrations of 5 to 6 bbl/min. After the composite fluid had been pumped, the well was flushed at the design rate until 40 bbl of flush volume remained before the perforations; at this point, the rate was reduced to 20 bbl/min as the composite fluid approached. After the composite fluid entered the perforations and pressure stabilized, the rate was increased to the designed rate and the pad was started on the second component of the job. The second component of the job consisted of another proppant-fracturing treatment, the same as in the first component; the amount of fluid and proppant pumped in each part was one-half of the amount in a conventional treatment. Overall, the total amounts remained generally unchanged when compared with a well treated without a sequenced-fracturing technique.

Data Analysis

A reference well and a case-study well were completed for the study to determine the effects of the new sequenced-fracturing technique, using both surface pressure and microseismic for evaluation purposes.

The reference well was completed by use of a conventional channel-fracturing technique for all stages, while the case-study well was completed in two sequential channel-fracturing stages with a composite fluid as a method of changing the clusters that were taking flow. Because of a high risk of screen­out, the first stage in the toe of the case-study well was completed by use of a conventional channel-fracturing technique without diversion. The subsequent 11 stages were completed by use of the sequential-fracturing technique. The amount of material in the composite fluid was the same for all 11 stages in which it was pumped. At the conclusion of the first portion of the case-study well, the pump rate was reduced from 60 to 55 bbl/min during the end of the stage, so that the pumping of the composite fluid would not exceed the maximum rate of 60 bbl/min.

As a component of the sequenced-fracturing technique, the effects of the diversion step between the proppant stages were evaluated by the use of surface-pressure response and downhole microseismic measurements. During placement of the composite fluid, the pump rate was held steady at 20 bbl/min so that pressure could be measured before achievement of diversion; the rate was not increased until the pressure leveled off to measure the maximum treating pressure after achievement of diversion. This difference in pressures between the pre- and post-composite-fluid conditions will be referred to as the diversion pressure for the stage.

The diversion pressure was measured in all of the composite-fluid stages and ranged from 490 psi to greater than 3,000 psi, with an average diversion pressure of 1,200 psi (Fig. 2), using less than 100 lbm of diverting material for the composite fluid. These values of diversion pressure are remarkable given the small amount of diverting material pumped in each stage.

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Fig. 2—Diversion-pressure variation during the various stages with the sequential-fracturing technique.

During Stage 10, the post-composite-fluid stage was reduced slightly because of the extremely high diversion pressure encountered that was perpetuated throughout the remainder of the job. All of the other stages were pumped to completion.

Three case studies were run in which all inputs were identical except for the fracture gradients along the wellbore (please see the complete paper for details of the case studies). The case-study results demonstrate that, without changing the plugging efficiency of the composite fluid, significant differences in diversion pressure can be observed. It is therefore reasonable to conclude that the differences in diversion pressure are caused by the redistribution of flow and the initiation of new fractures. These redistributions are a result of differences in stress variation from stage to stage, rather than of variations in plugging efficiency of the material. This change in flow distribution throughout the clusters also manifested itself in higher treating pressure in the second proppant-fracturing segment of the job.

Diversion was confirmed by the results of the microseismic monitoring. On both wells, the microseismic-monitoring data were used to calculate the fracture geometry and events over time. In both of the wells, a steady number of events were observed over the course of the operations. In the reference well, using the conventional fracturing technique, most of the early events occurred in the clusters in the direction of the toe. Approximately halfway through the operation, after the net pressure increased, the events stopped in these clusters and began to occur near the clusters nearest the heel. In the case-study well with the sequenced-fracturing technique, in the early stages of the operation, the events can be seen to occur toward the toe in a fashion similar to those in the reference well. Approximately halfway through the first part of the treatment, events can be seen to occur near the heel. After the composite fluid has been pumped, the events occur in between the previous events, indicating that the middle portion of the clusters was being fractured in the second stage of the treatment.

The wells were placed on production and were flowed in a similar fashion, with similar choke sizes and drawdown pressures. Because the lateral lengths were different for these two wells, corresponding nicely to the number of stages and fracturing treatments, the overall production was normalized to lateral length. After 160 days, the cumulative oil-equivalent production for the case-study well was 15% higher than that of the reference well (Fig. 3). The production increase suggests that more of the clusters in the lateral were treated, which increased the overall production of the well.

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Fig. 3—Cumulative production from both wells, normalized to lateral length.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 169010, “A Novel Completion Method for Sequenced Fracturing in the Eagle Ford Shale,” by C. Kraemer, SPE, B. Lecerf, J. Torres, SPE, H. Gomez, and D. Usoltsev, SPE, Schlumberger, and J. Rutledge, SPE, D. Donovan, SPE, and C. Philips, SPE, Marathon Oil, prepared for the 2014 SPE Unconventional Resources Conference—USA, The Woodlands, Texas, USA, 1–3 April. The paper has not been peer reviewed.