Special Report: Single solution controls produced water, sand

May 15, 2006
A new treatment offers a single two-step process for attacking the problems of sand and water in a producing well.

Stephen Ingram, Halliburton Energy Services, Oklahoma City

Terry Daniel - Payne Exploration Co., Oklahoma City; Earl Webb, Philip Nguyen - Halliburton Energy Services, Duncan, Okla.

A new treatment offers a single two-step process for attacking the problems of sand and water in a producing well. The new process provides a viable and cost-effective treatment for reducing water and solids production.

Generally, the industry previously has addressed these unwanted by-products of oil and gas production as separate problems requiring different treatment solutions. The new water-sand control treatment is a less-invasive approach for reducing water and solids that can facilitate hydrocarbon flow.

This two-step process can reduce the time spent on remediation treatments by limiting the number of workovers required to address water and solids production. Less time spent on remediation results in lower costs and higher profits.

Water, sand production

Production of large amounts of water from oil and gas wells is a major expense.

Many oil wells produce a gross effluent greater than 80% by volume of water. As a result, lifting water expends most of the energy for pumping a well, and also the separation processes for recovering water-free hydrocarbons add more costs.

Disposal of the remaining water is also troublesome and expensive.

For these reasons, it is highly advantageous for an operator to decrease the produced water from oil and gas wells. Another benefit is that decreased flow of water into the wellbore can help lower the liquid level above the downhole pump, reducing backpressure on the formation, improving pumping efficiency, and increasing net oil production.

Another expensive by-product that frequently accompanies oil and gas production is production of formation sand and fines particulates, often preceded by water intrusion.

At the water intrusion, cementation between formation sand grains can deteriorate, allowing formation sand and fines to migrate into the produced fluids. The higher the flow rates, the worse the problem.

Fines migration often causes formation damage as pore channels or flow paths become plugged with fine particles. The wellbore can become filled with formation sand, choking off the production flow path and requiring workovers to remove the sand fills.

Formation particulates in the produced fluids also can erode downhole and surface equipment.

Water, sand control

The new water and sand control treatment can tackle and overcome water and solids production at its source. The treatment involves injecting into the formation a relative permeability modifier (RPM), which is a water-flow-resisting polymer that attaches to adsorption sites on porous surfaces and reduces the water flow without substantially reducing the hydrocarbon flow.

The RPM is a hydrophilically modified, water-soluble polymer. Hydrophobic modification imparts improved adsorption characteristics to the polymer that reduce a formation’s permeability to water with little reduction in permeability to oil and gas.1

In the treatment, the injected one-component consolidating agent coats the surfaces of formation particulates. This agent forms a tacky, thin film of resin that creates bonds between grains and cures with time and temperature.

Unconsolidated formation sands, even those with high clay fines content, are consolidated with negligible loss of initial permeability. Combining the resin with the activator into a single component helps ensure that wherever the formation matrix is treated, consolidation will take place, providing more certainty than is often experienced with other consolidation treatments.

In addition, rather than the instant curing that usually occurs with acid catalysts, curing of the resin in with the new treatment takes place slowly to allow complete placement into the formation and complete displacement from the pore spaces within the formation matrix.2

Treatment processes

The water-sand control treatment uses two sequential steps to mitigate water cut and control produced formation sand and fines during well production.

Step 1 involves the injection of a relative permeability modifier (RPM) polymer into the interval, whether or not propped fractures exist within the interval. Without propped fractures, the RPM polymer penetrates the formations surrounding the wellbore (Fig. 1a).

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After Step 1, Step 2 displaces the RPM polymer farther into the formation. The Step-2 treating fluids include a displacement fluid, a consolidating agent, and an overflush that transform the weakly consolidated or unconsolidated formations surrounding the wellbore into a consolidated, permeable sand mass. This process locks in place the formation sand and fines (Fig. 1b).

With propped fractures, the RPM polymer enters the fractures and invades the proppant pack and formations along the fracture faces and near-wellbore region (Fig. 2a). The consolidating agent transforms the loosely packed proppant in the fractures and the formation sand close to the wellbore into a cohesive, consolidated, yet highly permeable pack bed.

This bed can withstand the high drawdown of production without producing back sand or proppant (Fig. 2b).

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Following this two-step treatment, the well is shut in. The amount of shut-in time depends on the bottomhole temperature of the well and can range from 2 to 48 hr.

The water-sand control treatment also can be part of a screenless, frac-pack completion. In this case, a consolidating agent, at a matrix pump rate, first treats the unconsolidated near-wellbore formation. Next, an RPM polymer injected as part of the pre-pad of the fracturing treatment, at a pump rate above the frac gradient, creates fractures bypassing the near-wellbore area previously treated with the consolidating agent (Fig. 2c).

In the final step, a proppant coated with liquid-curable resin fills or packs the created fractures. The resin consolidates the proppant into a solid, permeable mass.


Bullheading down the tubing and casing liner or injection through coiled tubing coupled with a DeepWave tool can place both the RPM polymer and the consolidating treatment fluid into the interval (Fig. 3).

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The DeepWave stimulation tool is a downhole-pressure pulse generator that provides enhanced fluid placement and helps improve production through wave generation and pore-scale dispersion. Halliburton runs the tool under a license from Wavefront Energy and Environmental Services, Inc.

The tool has three components:

  1. Power section for converting fluid flow to tool rotation.
  2. Gear reduction system.
  3. Pulse generator engine to create a large-amplitude, low-frequency pulse.

The tool uses downhole pulsing and is based on the following principles:

  • Large-amplitude, low-frequency pulsing enhances the flow of fluids in porous media.
  • The tool generates porosity dilation waves and causes pressure effects.
  • Porosity dilation effects create pressure waves that force fluids into normally unoccupied pore spaces.

Operators can apply the water-sand control treatment in both cased and openhole wells and in either new completions or in wells containing gravel packs or propped fractures. The treatment also can be injected into acidized intervals.

The water-sand control treatment involves the following steps:

  • Injecting RPM polymer into the formation at matrix flow rate.
  • Injecting displacement fluid to displace the RPM farther into the formation and conditioning the formation matrix near the wellbore.
  • Injecting a consolidating agent into the formation.
  • Injecting a displacement fluid to displace excess consolidating agent from occupying the pore spaces in the matrix of the formation.
  • Shutting in the well to allow the RPM polymer to firmly adsorb onto the surface of the formation sand and allow the curable resin fully to cure.
  • Producing the well after the shut-in period.

Case study

A gas well in central Oklahoma fractured with resin-coated proppant (RCP) is an example of the benefits of the treatment.

Following a production period in which proppant did not produce back, the well eventually began to produce proppant and formation sand as well as increased water, while the gas production rate declined. Also large amounts of proppant and sand fill in the wellbore choked off the perforated interval.

After several workovers with coiled tubing for removing sand fill in the wellbore, the operator decided to shut in the well and apply the water-and-sand control treatment to solve the solids and water production problems.

The well has two producing interval at 9,500 ft with a total length of 14 ft. The well was fractured with 54,000 lb of RCP.

The formation has a 0.1-5 md permeability and a 165° F. temperature.

The treatment used coiled tubing with an attached DeepWave tool to place 4,000 gal of RPM and 50 gal of consolidating agent into the perforated intervals at a 1 bbl/min injection rate. After the treatments, the well was shut in for 48 hr to ensure complete anchoring of RPM polymer onto the formation’s sand surface and curing of the consolidating agent between particulates.

After the shut-in period, the operator allowed the well to flow back and begin producing.

The average water-production rate before treatment was 325 bw/d (Fig. 4a) compared with 160 bw/d after the water-sand control treatment (Fig. 4b).

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The operator observed no apparent flowback of proppant or formation sand after the first 2 weeks following the treatment. Four weeks after the treatment, a check of plugback true depth (PBTD) with wireline indicated only 1 ft of solids in the wellbore.

The operator plans to install a submersible pump in the wellbore to obtain the desirable gas production flow rates.


1. Eoff, L., et al., “Development of a Hydrophobically Modified Water Soluble Polymer as a Selective Bullhead System for Water-Production Problems,” Paper No. SPE 80206, SPE International Symposium Oilfield Chemistry, Houston, Feb. 5-7, 2003.

2. Nguyen, P.D., et al., “Stabilizing Wellbores in Unconsolidated, Clay-Laden Formations,” Paper No. SPE 86559, SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, La., Feb. 18-20, 2004.

The authors

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Stephen R. Ingram ([email protected]) is a technical adviser to the US Midcontinent for Halliburton Energy Services, Oklahoma City. He previously worked for NANA Corp. on managing environmental projects at Prudhoe Bay oil field. Ingram holds a BS in chemical engineering from the University of Missouri at Rolla. He is a member of SPE and SPEE.

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Terry A. Daniel works as a petroleum engineer performing drilling, completion, production, and reservoir engineering duties for Payne Exploration Co., Oklahoma City. He previously worked for Helmerich & Payne Inc. Daniel holds a BS in petroleum engineering technology from Oklahoma State University. He is a registered professional engineer in Oklahoma and is a member of SPE and AADE.

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Earl Webb is a principal mechanical technologist in the tool systems group at Halliburton’s Duncan Technology Center, Duncan, Okla. He has 26 years’ experience in downhole tool design including casing equipment and coiled tubing tools. He is an SPE member.

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Philip Nguyen is a technical advisor in technology with the production enhancement group at Halliburton Technology Center, Duncan, Okla. He has more than 16 years of experience in the oil and gas industry. Nguyen has a PhD in chemical engineering from the University of Oklahoma.