Well-control fluids were used during a routine overbalanced workover operation in an offshore well completed in high-permeability sandstone. A fluid-loss-control pill was used to control excessive losses; however, because of the high permeability of the reservoir and the absence of sized particles in the pumped pill, a large amount of fluid was lost to the formation. A comprehensive review, accompanied by laboratory work, was conducted to identify the damaging mechanism and formulate a remedial treatment.

Polymer-based fluids are beneficial in terms of generating viscosity to clean out the wellbore during any well intervention. Improper polymer selection has led to significant formation damage in several situations. Polymers also can invade the high-permeability zones, hampering hydrocarbon flow through the zones. Bipolymers generally are removed through acidizing, which breaks down the polymer backbone. The damage caused by polymers can be minimized with proper polymer selection.

Standard remedial treatments for removing the near-wellbore polymer include injecting solvents (e.g., xylene), acids, alcohols, glycols, surfactants, or a mixture of these liquids into the well.

In sandstone well treatments, formation composition should be considered carefully, especially minerals susceptible to acid attack. Three potential damaging mechanisms can occur during sandstone acidizing: formation deconsolidation in acid; reprecipitating during primary, secondary, and tertiary reactions; or the release of fines because of partial decomposition of minerals in acid.

In the case of damage with oil-based material or emulsions, microemulsion treatments have been recommended. The microemulsion will solubilize the oil and emulsions and fluidize the filter cake into a single mesophase while dissolving the acid-soluble particles and making the solids and formation rock water-wet. The oil-based-mud particles in a filter cake will disperse, allowing the produced fluid to displace these blocking particles from the damaged zone into the wellbore and through any screens.

The well in question was drilled and completed initially as an oil producer with an inflow-control-device/sandscreen completion installed in the horizontal lateral across the reservoir. Because of some issues with completion hardware in the well, a workover operation was conducted that revealed significant formation damage/production impairment. During the workover, multiple cement plugs were spotted in the top sandscreen bore to create a barrier. Before the cement job, production tubing was punched and 309 bbl of diesel and 540 bbl of NaCl brine with hydroxyethylcellulose (HEC)/xanthan gum (XC) polymer were bullheaded in an attempt to clean the production string. Inadequate circulation access from the tubing puncher, an untreated pre-existing well-fluid-loss condition, and a poor cement-plug cleanup with a viscous HEC pill are believed to have compromised the entire wellbore-cleanout success.

After pulling out tubing, the well was cleaned and stimulated further with microemulsion-acid treatment before flowback, though with limited success. After initial post-microemulsion cleanup, the flowback showed emulsion returns. The well was then treated with a solvent. Thereafter, 100% oil was recovered, but natural well production could not be sustained.

During well completion, multiple fluids not only were circulated downhole but also were injected into the well formation. It was suspected that the subsequent treatment fluids—microemulsion acid and solvents (cutting wash and demulsifier) spotted and injected across the lateral—may also have reacted with the earlier fluids lost and injected, to form damaging byproducts in the well.

Generally, all the introduced ­completion-fluid materials and existing preworkover wellbore fluids were identified as subjects of investigation. These included microemulsion, brine, HEC/XC polymer brine, cement-slurry filtrate, and diesel.

Formation-damage laboratory evaluation was designed to be consistent with the preliminary formation-damage diagnosis. Fluid-chemical samples were first analyzed, and compatibility tests were conducted to generate emulsion or precipitate that was similar to that observed in the field. Thereafter, potential treatment-fluid options for damage removal were evaluated to determine the most effective option for the well conditions.

Fluid-chemical samples were first analyzed and compatibility tests were carried out to generate emulsion or precipitate similar to that observed in the field. Thereafter, potential treatment-fluid options for damage removal were evaluated to determine the most effective option for the well conditions.

Simulation of the Fluid-Reaction Byproducts/Emulsion Samples. Previous laboratory evaluations indicated that there was no incompatibility issue between microemulsion-treatment formulation and the formation crude and formation water. Nonetheless, it was considered important to verify this observation because emulsion was observed during the post-treatment well cleanup.

Treatment-Fluid Options for Recovered Field Samples and Fluid-Reaction Byproducts. The performance treatment-fluid options considered for removal of the recovered field emulsion sample and any other identified laboratory incompatibility sample were benchmarked against the microemulsion-fluid-treatment formulation applied in the well.

Coreflood. A coreflood apparatus was built to simulate fluid flow in porous media in the reservoir. A positive-displacement pump equipped with a programmable controller was used to deliver fluids at constant flow rates. A set of valves was used to control the injected fluid into the core sample. Pressure transducers were used to measure the pressure drop across the core. A convection oven was used to provide a temperature-controlled environment.

Simulation of the Wellbore Fluids Interaction To Replicate Emulsion Formation. Microemulsion treatment with wellbore fluids including viscous pill, crude, cement filtrate, and combinations of these was performed to evaluate any potential precipitation or emulsion. Compatibility tests were conducted at simulated reservoir temperature of 160°F and aged for 24 hours. The microemulsion treatment was mixed with different fluids at three different volume-percent ratios.

Analysis of the interaction between treatment solution and HEC/XC viscous brine revealed no indication or visualization of any separation or precipitation that could be the source of damage. When microemulsion treatment was mixed with crude, it did not show any indication of emulsion and the two liquids separated with a clear interface between them. When microemulsion treatment was mixed with HEC/XC viscous brine then mixed with crude, it showed the potential of emulsion.

Cement filtrate was mixed with crude oil at different volume ratios and showed emulsion tendency, especially at a 1:3 ratio of filtrate to crude. Mixing microemulsion treatment with cement filtrate did not show any negative interaction, indicating good compatibility. To evaluate the effect of microemulsion fluid on preventing or enhancing emulsion tendency, cement filtrate was mixed with microemulsion at a 1:1 ratio before being mixed with crude at different volume ratios. The test showed that microemulsion had a positive effect and prevented the formation of emulsion.

Only two cases showed potential emulsion: viscous HEC/XC brine and cement filtrate. Adding microemulsion helped prevent emulsion in all cases.

Field-Sample Identification. Viscous brine showed the highest potential of forming emulsion because large amounts of HEC/XC brine were lost during the field operation. High-viscosity HEC/XC brine was prepared and analyzed with nuclear magnetic resonance (NMR) to be used as reference. The NMR signal generated from the aqueous part of the field sample after the emulsion was broken matched the previous signals from the sample prepared in the laboratory, indicating that the viscous pill aggravates the formation of emulsion.

Treatment To Remove Field Emulsion Samples. Experiments were conducted to assess the ability of the pumped microemulsion solution and proposed treatment to break the emulsion. If the pumped treatment broke the emulsion, it would eliminate the possibility that the loss of productivity was from emulsion blockage. The first two experiments were conducted using the previously pumped microemulsion-based fluid. The first experiment uses the complete package with 10% acetic acid, and the second was without the acid. Both showed the ability to break the emulsion. A second set of experiments was conducted to develop and evaluate an alternative treatment based on formic acid to break the field emulsion. That proposed formulation was also able to break the emulsion.

Formation-Damage Diagnosis and Remedial Treatment Design. Review of the field operation and initial laboratory work indicated that loss of the viscous pill to the formation could be the damage mechanism in this case. The initial microemulsion with acetic acid was designed to treat any emulsion and damage on the sandface but did not penetrate deeply enough to remove the polymer damage. The proposed treatment targeted a larger-volume treatment with deeper invasion. The proposed stimulation fluid should take care of the emulsion in the wellbore and at the sandface and should be compatible with formation rock, to prevent any negative interactions with clay that can worsen performance.

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 174279, “Formation-Damage Diagnosis Facilitates a Successful Remedial-Treatment Design and Execution in Sandstone Horizontal Oil Producer: A Laboratory and Field Case Study,” by M.A. Bataweel, SPE, A.H. Al-Ghamdi, SPE, P.I. Osode, SPE, T.A. Almubarak, SPE, E.S. Azizi, SPE, Eddy Sarhan, SPE, and M.G. Al-Faifi, SPE, Saudi Aramco, prepared for the 2015 SPE European Formation Damage Conference, Budapest, Hungary, 3–5 June. The paper has not been peer reviewed.

The Journal of Petroleum Technology, the Society of Petroleum Engineers’ flagship magazine, presents authoritative briefs and features on technology advancements in exploration and production, oil and gas industry issues, and news about SPE and its members.

ISSN: 1944-978X (Online) ISSN: 0149-2136 (Print)