Roughly 75% of the formations drilled contain reactive shale and over 90% of wellbore stability problems are related to the inability of drilling fluids to control reactive shale. The most important variable in maintaining shale stability is preventing pore pressure invasion into the shale matrix. Pressure invasion alters the near wellbore stress state and can induce failure. Shale stability is achieved when pressure invasion is reduced and differential pressure support is maintained.

TERRA-MAX is a high-performance water based mud (HPWBM) with performance approaching

Figure 1. Deformable sealing polymer (Images courtesy of Baker Hughes Drilling Fluids)
an oil-based mud (OBM). Developed by Baker Hughes Drilling Fluids, it balances reduced environmental impact with increased operational efficiency. The system inhibits reactive formations encountered in onshore and inland water applications.

The HPWBM incorporates a micronized deformable sealing polymer that mechanically bridges shale micro-pores and micro-fractures.

Additionally, the deformable nature of the polymer allows the “mold” along fractures and pores to effect better bridging of shale matrix or other low porosity formations such as tight gas permeable sands. This sealing effect reduces pressure invasion thus maintaining borehole integrity.

Clay inhibition
The inability to suppress hydration in reactive clays leads to problems such as bit balling, accretion, poor solids removal efficiency, high dilution rates, filtration control and control of rheological properties. Reactive clay swelling, along with pore pressure transmission, is a leading cause of shale instability.

Clay hydration occurs from surface hydration, bonding of water molecules to oxygen on the surface of the clay, and ionic hydration, which is hydration of interlayer cations with surrounding shells of water molecules. Surface and osmotic absorption result in two distinctly different problems: swelling, which is the expansion of the clays due to water uptake, and dispersion, which is the disintegration of the clay fabric after hydration.

Clay inhibition is more difficult to achieve with water-based systems due to the similarity of the wetting characteristics between the drilling fluid and the formation. The new HPWBM uses an environmentally acceptable water-soluble clay hydration suppressant to stabilize highly reactive clays through a cation exchange mechanism. The suppressant effectively inhibits reactive clays from hydrating.

Rate of penetration
Conventional WBM typically exhibit low rates of penetration (ROP) as compared to those
Figure 2. On wells field-tested with TERRA-MAX, cost savings have been substantial.
delivered when drilling with OBM. The drilling of soft, reactive formations often presents a problem with regards to bit balling and consequently a reduction in ROP. Bit balling is due to reactive clay accretion on the water-wet bit and bottomhole assembly (BHA) which that effectively prevents the bit from cutting new formation. The new HPWBM contains a ROP enhancer that preferentially “oil wets” the bit, drill string and other metal components with environmentally friendly base fluids and surfactants. It effectively renders them hydrophobic, reducing the tendency of reactive clays from adhering to the bit and bottomhole-assembly (BHA) surfaces.

A proprietary method of addition is used to inject the ROP enhancer so that a continual, non-emulsified stream of additive is contacting the bit while drilling. This provides a step change in performance by minimizing mechanical emulsification and reducing concentrations of the product needed to deliver performance.

Lubricity
Land drilling rigs are typically limited by available horsepower. As land wells get deeper and more complex in wellbore trajectory, torque and drag becomes an important issue particularly when drilling with a water-based mud (WBM). A secondary function of the ROP enhancing additive is a reduction of frictional forces arising from contact between the drilling assembly, tubulars, and the open hole. Friction factors are representatives of the true friction coefficient of a drilling fluid. Based on torque and drag field data, the new HPWBM has been shown to exhibit friction factor values approaching those of OBM.

Reduced differential sticking and mud losses
Stuck pipe due to differential pressures encountered over depleted zones is problematic with WBMs as well as OBMs. The deformable sealing polymer developed for the new HPWBM used with the proper selection of lost-circulation material (LCM) has proven to reduce differential sticking in depleted zones. Because the deformable sealing polymer is composed of deformable colloidal particles, it will bridge at the borehole interface of low permeability formations such as tight gas sands. This bridging creates an external filter cake as well as an internal filter cake.

The internal filter cake also enhances the effective rock strength, which increases formation fracture resistance. This effective rock strength enhancement allows depleted sand to be drilled with the appropriate mud weight required to control inter-bedded pressured shale while potentially reducing mud losses to the depleted formation.

Environmental
The new HPWBM system is designed to provide wellbore stability in a freshwater or low salinity environment. This is a considerable advantage for waste treatment in land environments. During a multi-well campaign, the system used on the first well can be recycled and a portion can be reused on the upcoming jobs. This not only saves the operator mixing and rig time, but also reduces the overall amount of fluid required, ultimately reducing the consumption of water and the overall environmental impact of the drilling operations.

Wellbore quality
Another performance measure for any drilling fluid is a quality borehole for non-drilling operation such as cementing and logging. Poor cementing jobs can be attributed to wash-out of the well bore and poor cement bond. Ideally, cement will bond better in a water-wet environment rather than an oil-wet environment. The new HPWBM has proven to achieve a gauge well bore, even after extended openhole exposure.

Case study
An operator in South Texas used the new HPWBM system to evaluate an alternative to traditional water-based systems on three wells. Lignosulfonate systems have traditionally been used in the area. The use of these systems typically results in incidents of stuck pipe and lost returns. The HPWBM was evaluated to determine if its ability to reduce pore pressure transmission and seal microfractures would reduce lost circulation and stuck pipe events in tight gas sand formations.

The initial well was displaced to the HPWBM at 10,424 ft (3,177 m) during a bit trip and after drilling with spud mud. Four tight-gas sand zones were encountered without experiencing any lost circulation or stuck pipe events. Drilling continued to 13,467 ft (4,105 m) where logs and casing were run without problem. The well had been engineered with a contingency liner expecting losses and possible stuck pipe. Due to the successful and trouble free penetration of the depleted sand zones, the operator made the decision to drill to TD total depth without running the liner. This 8 1/2-in. (216 mm) interval was drilled six days faster than planned and saved US $300,000 in rig time.

The second well was displaced to the HPWBM at 10,680 ft (3,255 m) after running 95¼8-in. casing. As in the first well, tight gas sand zones were encountered without experiencing any lost circulation or stuck pipe events. Drilling continued to 13,811 ft (4,209 m) where logs and casing were run without problem. After the first successful well was completed, an after action review was conducted to evaluate the lessons learned with the system. The lessons learned were applied to the second well, which was subsequently completed 10 days ahead of schedule and more than $50,000 under programmed cost. Ultimate cost savings was more than $550,000.

A third well was displaced to HPWBM at 11,100 ft (3,383m) after running 95¼8-in. casing with no lost circulation or stuck pipe events. Drilling continued to 13,500 ft (4,115 m) where logs and casing were run without problem. The third well was completed 11 days ahead of schedule and more than $55,000 under programmed cost. Ultimate cost savings were more than $600,000.