Pillar Fracturing a Sandstone Reservoir Shows Benefit Over Conventional Fracturing

Topics: Hydraulic fracturing
Fig. 1—Comparison of conventional fracturing, left, and pillar fracturing. Xf=fracture half-length.

You have access to this full article to experience the outstanding content available to SPE members and JPT subscribers.

To ensure continued access to JPT's content, please Sign In, JOIN SPE, or Subscribe to JPT

The Kaji Semoga Field in South Sumatra consists of three main reservoirs—Telisa sandstone (TLS), Baturaja limestone, and Talangakar sandstone. The successful development of TLS with hydraulic fracturing led to further efforts to maximize oil recovery. After a study with suitable samples and cases, pillar fracturing was considered. This method is similar to conventional fracturing techniques where fluid and proppant are used to create conductive paths in the reservoir layer; however, pillar fracturing relies on open flow channels.

Pillar Fracturing

A major step change in the development of the Kaji Semoga Field was to use the hydraulic-fracturing technique referred to as pillar fracturing. The pillar-fracturing technique creates stable voids within the proppant pack that serve as infinite-conductivity channels for fluid flow rather than the intragranular flow of conventional fracturing techniques (Fig. 1 above). Hydrocarbon will flow preferentially through the channels rather than through the proppant pack. In addition, pillar fracturing allows for better fracture cleanup, longer fracture effective half-lengths, and lower pressure drops along the fracture. Consequently, production after pillar fracturing is greater than that following conventional fracturing. Another advantage of the pillar-fracturing technique is a low screenout rate compared with conventional fracturing. The prevention of screenout is related to the different bridging characteristics of conventional- and pillar-fracturing slurries.

The stable voids within the proppant pack are created through a combination of specific pumping schedules, specific equipment, and fracturing-fluid design. The voids are achieved by alternate pumping of gelled fluid in two types of pulses, proppant-laden pulses and proppant-free pulses. Fibers are added continuously during pumping to mitigate the dispersion of the proppant-laden pulses as they are conveyed throughout the surface lines and the wellbore and within the fracture. A dispersed pulse can create narrow fracture widths and a reduction in the number and quality of the channels, which leads to a reduction of fracture conductivity. The fiber also enhances the proppant-carrying capacity and prevents proppant settling within the fracture. The pulse stage is then followed by a continuous proppant tail-in stage near the end of the treatment before the flush stage. This tail-in stage ensures good connectivity between the wellbore and the channels created during the treatment. Specially engineered blending equipment was needed to ensure stable and consistent pulse delivery. 

Not every well is a candidate for pillar fracturing. Main requirements for candidate wells include a Young’s modulus greater than 2.5 million psi, a minimum in-situ stress or closure pressure lower than 13,000 psi, and a ratio of Young’s modulus to closure pressure of greater than 275. These requirements ensure that the channels inside the fracture stay open and will not collapse when the fluid pressure declines during leakoff. The stiffness of the formation compensates against the bending stresses on the rock to avoid pinching or closure of the open channels after the fracturing fluid in these channels has leaked off.

Pillar Fracturing

Data from 12 wells were reviewed using a multidisciplinary approach to select the top two wells for the field trial. Some important parameters, such as reservoir-pressure gradient, average permeability, oil saturation, barrier thickness, neutron porosity, gas reading, net pay, oil show, and stress contrast between the TLS and the Baturaja limestone, were selected and assigned relative weight on the basis of importance and data reliability. Then, the value of the selected parameters was averaged and totaled for every well. Because some required data were missing, the best well was identified on the basis of the highest average value and not the highest total value. In addition, other considerations, such as gas-cap location, cement-bond log, location of injector wells, well readiness, and well history, were considered and appraised. Two wells (KS-E and KS-L) were selected for the field trial.

To execute pillar fracturing, specific fracturing-design software was used and particular equipment requirements must be met. The blender used in this operation needed to have upgraded firmware that could control the proppant gate’s opening and closing within 1 second. A function test on location was conducted to simulate the real job, identify any potential risks during main fracturing, and generate mitigation measures for any operational failure.

Three types of injection test were executed before the main fracturing treatment in each well—a mini-falloff test, a step-rate test, and a mini-fracture test. The result from those tests were used to recalibrate the preliminary model and redesign the pumping schedule.

The main fracturing was pumped with borate-crosslinked fluid at a rate of 18 bbl/min. Two sizes of proppant were used—20/40 intermediate-strength proppant (ISP) and 12/18 ISP. The 12/18‑mesh size was used to create the high-conductivity tailed-in stage near the wellbore. The average surface treating pressure was approximately 1,800–2,000 psi. During the main fracturing, the surface pressure increased as 12/18 ISP started to enter the formation, which indicated a restriction in the near-wellbore region.


Post-treatment evaluation showed that fracture conductivity for wells fractured with the pillar-fracturing technique is five times that in wells fractured with conventional fracturing. Meanwhile, fracture length created per pound of proppant for wells fractured with pillar fracturing is 61% greater in Well KS-E and was similar in Well KS-L. This higher conductivity led to oil production up to two to eight times greater.

Post-fracturing production results in Well KS-E, which was fractured with pillar fracturing, showed a higher initial production compared with that of a nearby offset well. Production rates were also stable at approximately 423 BOPD with water cut of 3.39% for 182 days compared with the flow rates expected from a conventional fracturing treatment. Meanwhile, oil production from Well KS-L increased gradually and stabilized at 200 BOPD as water cut decreased from 97% to 0.05% at 173 days. Normalized production with reservoir pressure for wells fractured with the pillar-fracturing technique was higher than for wells fractured with conventional fracturing. The low water-cut value indicates that the fracture is not growing into the Baturaja formation. Screen­out was also eliminated when the pillar-fracturing technique was applied.

Beside production rate after fracturing, well productivity index (PI) was also evaluated to examine post-fracture production decline that the pillar-fracturing technique aimed to overcome. Highlights from the two pilot pillar-fracturing wells include that well performance reaches stable condition approximately 2 weeks after fracturing and that the decrement of PI for those two wells is similar at approximately 40%. This phenomenon is explained by the fact that, for typical wells in the Kaji Semoga Field, the fracturing-fluid-recovery period is approximately 2 weeks after fracturing.

Summary and Way Forward

Pillar fracturing is one of the techniques considered to maximize production from the TLS in the Kaji Semoga Field. Production after pillar fracturing showed a 56% increase compared with that of a nearby offset well, even though the reservoir pressure was already depleted and the reservoir Young’s modulus was at the tail end of the application envelope for pillar fracturing. Proper candidate selection is critical to increase the rate of success.

This successful field trial of pillar fracturing will open more paths for the application in other wells and reservoirs with similar characteristics.

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 186199, “Unlocking Depleted and Low-Modulus Telisa Sandstone Reservoir With Pillar-Fracturing Technique: Well-Performance-Improvement Comparison With Conventional Fracturing,” by M. Azhari, SPE, N.F. Prakoso, and D. Ningrum, Medco E&P Indonesia, and L. Soetikno and A. Makmun, Schlumberger, prepared for the 2017 SPE/IATMI Asia Pacific Oil and Gas Conference and Exhibition, Bali, Indonesia, 17–19 October. The paper has not been peer reviewed.

Pillar Fracturing a Sandstone Reservoir Shows Benefit Over Conventional Fracturing

01 March 2018

Volume: 70 | Issue: 3