Highly inhibitive water-based fluid provides drilling performance comparable to invert emulsion systems in reactive shale sections.

In a Lavaca County, Texas, field most wells are drilled with conventional water-based fluids and diesel-based invert emulsion fluids. However, excellent drilling performance has been achieved with a high-performance, water-based fluid (HPWBF). Using the HPWBF, a stable-gauge hole was drilled at a rate of penetration (ROP) comparable to invert emulsion systems. Fluids designated as HPWBF must 1) exhibit low colloidal content, 2) be highly inhibitive in reactive shales, 3) be run non-dispersed, and 4) exhibit a high degree of shear thinning.
The system reduced costs and risks associated with oil-based fluids. In reactive shales, the HPWBF helped minimize hole washout, optimize hole cleaning and improve the quality of cementing jobs. The HPWBF enabled a solids removal efficiency (SRE) in the 85% range, rivaling invert emulsion systems. Product consumption and discharge volumes were significantly lower compared to conventional WBFs. Haul-off and cleanup costs were reduced compared to invert emulsion fluids. Standard equipment on most rigs was sufficient to maintain desired properties.
The HPWBF system discussed here is designed for land applications and is formulated with fresh or low-salinity water. Early use of this HPWBF system in Calhoun, Webb and Zapata Counties (Texas) produced favorable results. As a result, an operator used this system to drill the intermediate interval of the Eaves No. 5 in the Speaks field, Lavaca County. Seven offsets were investigated. Intermediate sections typically were drilled from 2,800 ft to 10,600 ft (854 m to 3,233 m). Difficulties encountered on the offset wells included:
• Treatment for carbonate contamination;
• Logs not reaching bottom;
• Swelling shale;
• Packing off/bridging;
• Having to wash and ream to bottom;
• Excessive cuttings due to sloughing shale;
• Seepage losses;
• Partial and lost returns;
• Reduced pump rates to minimize losses;
• Slow penetration rates; and
• Wellbore instability because of insufficient mud weight.
System features
The HPWBF system exhibits low colloidal solids content and is highly inhibitive, non-dispersed and shear thinning. Low colloidal content is typically maintained with standard rig solids-removal equipment, although supplementary equipment can enhance solids reduction. The system is maintained without dispersants or caustic materials. Absence of dispersants helps to reduce colloidal solids content. The highly inhibitive nature of the system can improve wellbore stability and help minimize washout tendencies. The polymeric composition of this system results in a highly shear-thinning fluid.
Low colloidal solids and ROP
Reducing solids concentrations can lower plastic viscosities, improve filter-cake quality, increase bit life and improve penetration rates (Figure 1). Maintaining a low colloidal content in a WBF system has been the greatest obstacle to achieving ROPs comparable to invert emulsion systems. Minimizing the time that drilled solids remain in the fluid system is recommended in maintaining low colloidal content. The HPWBF system can lower colloidal content by using a high molecular weight (HMW) flocculating polymer. The encapsulating effect of this polymer on drilled cuttings helps reduce wellbore attrition and can result in fewer colloidal solids being generated. Minimal retention time is achieved when fine mesh screens are used to remove these larger drilled solids before further breakdown can take place.
The ROP achieved with the HPWBF on the Eaves No. 5 well was compared with ROP achieved in the vertical portion (±3,300 ft or ±1,006.5 m) of a well drilled in the same field using a diesel invert emulsion in the 12¼-in. intermediate section. The invert emulsion fluid averaged 69 ft/hr (21 m/hr) in the vertical portion of the interval; the HPWBF system averaged 63 ft/hr (19.2 m/hr) for the entire interval. Only one instance of tight hole occurred while making a bit trip at 8,725 ft (2,661 m). This problem was worked through successfully. Before drilling the interval to total depth, wireline logs were run without incident. A string of 95/8-in. casing was landed at approximately 10,600 ft (3,230 m) with no problems.
Solids removal efficiency
Although generation of colloidal solids is minimized, it is not eliminated. A benefit of the HMW polymer is the flocculation of drilled solid particles in the colloidal range. Reduced attrition rates and flocculation of colloidal drilled solids lead to improved SRE, resulting in lower dilution volumes, with a corresponding decrease in fluid system product consumption compared to other WBFs. An SRE study as part of this project indicated that the HPWBF provided removal efficiencies of approximately 85%, rivaling those of invert emulsions, typically in the 85-90% range.
A later dilution requirement study conducted on two wells in the same field indicated that the HPWBF system required 42% less dilution volume than the dispersed fluid system to maintain low-gravity solids at an acceptable range.
Solids in the 1- to 2-micron size range tend to plug the microfractures created by bit cutter impact and impede pressure equalization and the resulting lifting action. With the HPWBF system, there are fewer sub-micron particles to plug the micro-fractures, and as a result, rock chips are more easily removed and carried to the surface.
Non-dispersed fluid effects
The non-dispersed nature of the HPWBF system also helps to increase ROP. In a dispersed fluid, commercial products satisfy molecular charges, but as a consequence, total solids surface area increases, as does plastic viscosity. The aggregated or flocculated state of the HPWBF system presents a minimum surface area of clay platelets with a decrease in plastic viscosity and a corresponding increase of energy at the bit. These larger agglomerates also present fewer sub-micron particles that could impede pressure equalization across the chip and retard ROP (Figure 2).
Effective inhibition
The HPWBF system exhibits a large degree of inhibition due in part to the high molecular weight polymer and also the anionic polymers used to provide fluid-loss control, bentonite extension and additional inhibition. The anionic polymers adhere to clays in a plating fashion, preventing the absorption of water. The HMW polymer tends to wrap around clay particles helically, providing reinforcement and lessening the effects of attrition. The inhibitive nature of this HPWBF system was evaluated against that of a typical dispersed fluid system. Test results (Figure 3) indicate significantly less swelling compared to the dispersed fluid.
The inhibitive nature of this HPWBF leads to a more stable, near-gauge well bore. Caliper logs of wells drilled using the HPWBF and invert emulsion fluids were analyzed to determine wellbore enlargement. Based on calculated gauge wellbore volumes and wellbore volumes taken from the caliper logs, the HPWBF well showed an enlargement of 9.6% compared to 7.1% for the invert emulsion. This is a difference in actual hole diameter of less than 1/3 in.
Thixotropic properties
An ideal drilling fluid will exhibit decreased viscosity with increased shear. Viscosity affects hydraulics and cuttings removal. A less shear-thinning fluid is more likely to develop a "viscosity cushion" between bit cutters and the formation, reducing penetration rates. The low colloidal and polymeric content of the HPWBF results in a highly shear-thinning fluid with less drillstring pressure loss and more energy available at the bit. Low drillstring and bit pressure losses and high bit-hydraulic horsepower values were seen on the Eaves No. 5 well.
HSE benefits
The HPWBF system uses no dispersants or caustic materials. Improved SRE values help conserve water resources and reduce the waste stream. The basic components of the HPWBF system comprise about 2% of the volume compared to 4% for a dispersed system, which helps to reduce risk and costs. No aromatic wastes are produced.
Cost comparison: emulsion fluids
A 1999 study of wells drilled with diesel invert emulsion fluid systems in the Lobo trend of south Texas looked at ancillary costs associated with diesel-based systems but not necessarily
shown as part of the fluid system cost. The average interval length of the 15 wells was 2,055 ft (626.8 m), with an average wellbore diameter of 6½ in. Fluid system costs, exclusive of transportation and engineering, averaged US $28,600 per interval. Ancillary costs for the 15 wells averaged $22,000, or 43% of the total. Ancillary costs are essentially eliminated when wells are drilled with the HPWBF discussed here.
Low colloidal solids content has a positive effect on ROP. The use of this HPWBF helped the operator to reduce or eliminate risks and costs of using invert emulsion fluids, without compromising performance.

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