Mature fields

Frac-Packing Previously Gravel-Packed Well Offers Alternative to Expensive Sidetracking

This paper details the design and execution of what the authors say they believe is the first successful frac-pack operation in a previously gravel-packed well.


This paper details the design and execution of what the authors say they believe is the first successful frac-pack operation in a previously gravel-packed well. The well, in China’s Bohai Bay, exemplifies a new method of recompleting mature wells to enhance production without performing a sidetrack, thus significantly reducing costs. Challenges and solutions are discussed as well as the methods used to squeeze fluid and proppant into the formation.


For the past 13 years, a single-trip multizone (STMZ) gravel-packing system has been widely used in Bohai Bay for sand control. The practice has been to run single-trip, multizone, wire-wrapped screen in the casing and then perform a gravel pack for each stage. In some wells, production can decline quickly and the well can stop flowing within a couple of years. A typical solution is to pull the upper completion, plug the lower completion, and sidetrack. The cost of this method can be significant. Operators desired a lower-cost workover plan that would restore production from the current completion. The proposed method involved recompleting a well by running in service tools to perform fracture packing within the existing multizone gravel-pack completion. High-viscosity fluid would be pumped into the formation as a prepad; then, fracture packing would be performed.

The reservoir of the Suizhong 36-1 field in the Liaodong Bay area of the Bohai Sea is composed of multilayer sandstone formations. This field experiences sand-production issues for several reasons.

  • Because of its high permeability and high porosity, the formation sand is unconsolidated.
  • Production began in 1993, and, over the years, water has been injected to maintain it. Currently, the average water cut is 70%. Water production can cause sand production.
  • The oil is heavy. It has a high asphaltene content, and its viscosity is 37–160 cp, which generates significantly high friction forces when flowing in the near-wellbore region, thus increasing the likelihood of sand production.

The treatment includes cleaning the wellbore for recompletion. Use of the STMZ system proved the downhole service tool could be tripped back in and out of hole safely in the same trip following fracture packing of a previously gravel-packed multizone well completion. The method also shows that, through careful planning and designing of the tool and treatment, the risk of failure caused by a stuck tool string, unwanted fluid loss, or premature screen­out can be minimized. The job execution and lessons learned also can provide a guideline for improvement of future treatments in similar situations.

Proposed Solution

In the original completion of the candidate well, four stages of 5.5-in. wire-wrapped screen were run in 9⅝-in. casing; then, each stage was gravel-packed with 30/40-mesh ceramic proppant. The gravel pack was performed in June 2014. Within 2 months, oil production declined significantly. However, a significant volume of unrecovered oil reserves is believed to remain. Thus, this well was selected for recompletion to attempt to recover lost production.

Although fracture packs have been successful in the Bohai region, the original completions were also fracture packs. To the authors’ knowledge, recompleting an originally gravel-packed well using fracture packing in the same completion had never been performed. As such, several challenges existed.

The original completion was designed for gravel packing. Thus, the pressure rating and screen design were not ideal for a frac-packing treatment. To address this issue, analyses were performed to calculate pressures for the tool design to ensure that the maximum bottomhole pressure would not exceed the allowed pressure rating of the current completion.

Another challenge was to create a flow path to place proppant into the formation. To enter the formation, the proppant needed first to pass through a port on a blank pipe located above the screen, then to travel in the annulus between the screen and production casing, and, finally, to enter the formation through perforations. However, the annulus between the screen and production casing was filled with gravel. To solve this challenge, at the beginning of the frac-pack treatment, a viscous gel fluid was pumped first at a rate sufficient to wash the gravel currently in the annulus into the formation to create a pathway for the proppant to enter into formation (Fig. 1).

Fig. 1—The steps used to create a flow path for the proppant: (a) original status, (b) pushing gravel into the formation, (c) status after gravel has been pushed into the formation, and (d) frac-packing.

Tool Design

The greatest challenge to the tool design was determining how to run the service tools to the desired position, because the well had already produced for 1 year and the downhole conditions were uncertain. The authors present a detailed discussion of the tool design and of a dry run conducted to confirm downhole conditions and clean the well at the same time. Details of the previous STMZ installation, dry-run workstring, and frac-pack service tools are included.

The complete paper also includes detailed discussions of the pressure calculation for the tools, frac-pack design and pumping schedules, running the dry-run assembly into the hole, pushing the previous gravel into the formation, and running the frac-pack service tool.

Frac-Pack Process

Two stages of the frac-pack operation were performed. A minifrac was performed to determine the fluid efficiency and adjust the pad volume. However, during shut-in, an unexpected pressure increase was encountered, which rendered the shut-in data after the pressure increase unsuitable for analysis. No clear closure event was observed from either log-log or G time curves. Fluid efficiency could only be roughly estimated to be more than 30%, and the pad volume was less than 50%.

The frac-pack main treatment then was performed. The process went well; however, tip screenout was not achieved. At the end, the rate was slowed and the annulus flow path was opened to allow some fluid to flow back instead of pumping it into the formation. When returned, the fracture began to close and proppant filled the annulus between the screen and production casing. Pressure was increased until reaching a kickout at 3,600 psi, which meant all of the annulus was filled. In total, 21,556 gal of fluid and 25,578 lbm of proppant were pumped.

After Stage 1, the tool was pulled to reverse position and fluid was pumped from the annulus to the tubing to clean out any proppant left in the tubing. After the tool was clean, the service tool was pulled to the circulation position for Stage 2. Steps similar to those in Stage 1 were performed. Fracture extension pressure was 1,150 psi, and fracture-extension rate was 5.2 bbl/min. In total, 16,906 gal of fluid and 17,470 lbm of proppant were pumped.


After the completion of the frac-pack treatment, the well produced at the same oil rate but at a much lower water rate. However, after approximately 3 months, water production increased again and caused oil production to decline.

Lessons Learned

A process for performing a frac pack in a previously gravel-packed well is established in this work. Candidate wells for such work typically would exhibit high near-wellbore skin or low productivity without necessarily high water cut. The frac-pack service tool needs to be designed on the basis of the current completion configuration, such as screen size and depth and sealbore inner diameter and depth. The seal assembly and crossover ports on the frac-pack service tool should match these current elements to create a flow path for the proppant to flow into the target zones. Calculations also must be performed for the pressure rating to ensure that the current completion can withstand the pressure requirements of a frac-pack treatment. A dry run to clean the wellbore is needed to ensure that the service tool can be run to target depth. Another purpose of the dry run is to push the existing gravel between the screen and production casing into the formation. This needs to be performed at a rate and pressure higher than the fracture extension conditions. High-­viscosity fluid, such as linear gel and crosslinked gels, can be used to push the gravel into the formation. Once a flow path is established, the frac-pack operation can be performed.

The results show that, after the frac-pack operation, production increased compared with the previous gravel pack. However, the benefit did not last long. This might result partially from not achieving tip screenout. The main cause, though, appeared to be water production. The fracture pack itself will not solve water-production issues. The newly created fracture pack provides a flow path for both oil and water. Without water-control measures, the production of water can return quickly and hinder oil production. For future wells, a candidate well that does not have water-­production issues would be preferred for the recompletion process. If the recompletion is to be performed on a water-producing well, a conformance treatment should be performed together with the frac-pack operation.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 191001, “Fracture Packing in Previously Gravel-Packed Well Using Single-Trip Multizone System,” by  Jianming Deng, Yingwen Ma, and Ming Zhang, China National Offshore Company; Jiacheng Qian and Chao Fang, Halliburton; and Qiang Wang and Xiaobo Wang,  formerly Halliburton, prepared for the 2018 IADC/SPE Asia Pacific Drilling Technology Conference, Bangkok, Thailand, 27–29 August. The paper has not been peer reviewed.