Screening criteria help select formations for underbalanced drilling

D. Brant Bennion
Hycal Energy Research Laboratories Ltd.
Calgary

Certain laboratory screening procedures can help determine the effectiveness of underbalanced drilling in a specific application.

These screening criteria can help in analyzing the types of reservoirs which present good applications for underbalanced drilling technology.

Part 1 of this series covered the potential advantages and disadvantages of underbalanced drilling operations and presented a list of potential damage mechanisms and high risk areas.

Experience has indicated that, when care is taken in the design of an underbalanced drilling program, in the right circumstances significant technical and economic benefits can be obtained. Conversely, application of a poorly conceived and executed underbalanced drilling program can often result in additional costs, greater damage, and reduced production in comparison to a well-designed conventional overbalanced program.

Although a properly executed underbalanced operation will give favorable results in almost any situation, comparable results may often be obtained with considerably less cost and risk with a conventional well-designed overbalanced drilling program in some reservoir applications.

The following information should be obtained for any reservoir prior to designing the underbalanced drilling program for optimum performance.

Reservoir parameters

The range of permeability, porosity, and pore-throat size distribution in the formation should be determined for bridging calculations and evaluating fluid loss potential (determined from routine core analysis, petrographic image analysis, and mercury injection porosimetry data).
The presence of macroscopic heterogeneities (vugs and fractures) and the aperture size of these porosity features (determined from downhole imaging, micro resistivity logs, and in some cases goniometric core analysis on representative core samples) should be determined.
Petrographic analysis of cores, sidewall cores, or cuttings can determine the presence of sensitive minerals (clays, anhydrite, halite, etc.) in the formation.
If potentially sensitive minerals are present (smectite clay, mixed layer clays, high concentrations of deflocculatable kaolinite, or other water-sensitive materials), the reaction of these materials with the proposed base mud filtrate/kill fluid should be carefully evaluated. In most operations it is highly likely that a certain amount of this fluid will invade the formation.
In situ initial saturation conditions of water and oil (if present) should be determined.
Log-based evaluations or regular core analysis can sometimes give erroneous estimates of initial saturation. If the core and near well bore region have been flushed with drilling fluid or if the core has been improperly handled or preserved and allowed to be desiccated or flushed with foreign fluids during the analytical process, then the saturation estimates could be wrong.
Well-calibrated deep induction logs generally give a reasonably good indication of Swi (initial water saturation) when coupled with data from hydrocarbon-based coring programs. Recent improvements in radioactively traced, low-invasion coring programs with conventional water-based systems have greatly improved the technology for the acquisition of accurate initial water saturation data at relatively low cost. 1 2
The true irreducible water or oil saturation level and capillary pressure characteristics of the formation will be required to determine if the initial reservoir saturation is at, or in excess of, the irreducible level. This information will help determine if phase-trapping effects will be problematic. Irreducible saturation data are best obtained from capillary pressure or dynamic desaturation tests conducted in a porous plate cell with restored-state-type cores.
A proper understanding of the wettability of the formation will be required to ascertain the potential for imbibition and phase-trapping effects. Knowing the wettability can help quantify the potential for high fluid loss rates with water-based filtrates in an overbalanced mode.
This effect is common in strongly oil-wetted systems because of high end-point relative permeabilities to water. Combined Amott/
USBM wettability tests are recommended on preserved/restored-state cores for this evaluation. This technique provides a quantitative definition of the degree of water/oil wetness. These tests also quantify hybrid wettability conditions such as neutral, mixed, or spotted wettability. Byproducts of the test are oil/water capillary pressure and saturation data, which are required to help determine the true irreducible water or oil saturation.
The presence of multiple potential zones and exact pressure expected in each zone should be known.
The concentration, composition, and size distribution of the natural drill solids expected should be determined. In most scenarios, it is assumed that the new fluid system will be used after an intermediate casing string is set. The concentration and size distribution of these solids will be a function of the solids control program.

Fluid parameters

The composition of in situ reservoir fluids should be determined using standard analytical techniques for oil, gas, and water analysis.
Flash limits of reservoir fluids with air (if air is considered for use as the gas medium) should be determined by direct flash envelope testing of the given reservoir fluid system.3
The potential emulsion, scale, and precipitation potential of the base drilling fluid with the in situ formation fluids should be determined using American Petroleum Institute compatibility test and computer simulation techniques.

Lab screening techniques

Several laboratory techniques are available to determine the properties described above and to quantify the effect of underbalanced drilling on a given formation.

The specifics of the equipment and procedures used for this type of testing have been described in other work.4 5 Fig. 1 is a schematic illustration of a typical underbalanced core-flood evaluation apparatus.

The following is a basic suite of tests conducted to contrast overbalanced and underbalanced drilling operations.

Underbalance evaluation

1. Obtain representative preserved or restored state samples at correct initial oil and water saturation conditions.

2. Measure initial, undamaged reference permeability to oil or gas (depending on the reservoir type under consideration) at varying conditions of drawdown pressure encompassing the range of expected field drawdown pressures. This measurement will help determine the presence of capillary or turbulence effects.

3. Conduct an underbalanced drilling fluid test by circulating the proposed drilling fluid in an underbalanced mode across the core face. Use the maximum expected underbalance pressure gradient across the core while continuously tracking permeability for 24 hr or until a stabilized dynamic permeability is obtained.

4. Degrade underbalance pressure in several stages, allowing 24 hr equilibration at each stage. Observe if countercurrent imbibition effects are apparent and reduce permeability as underbalance pressure is reduced. Conclude with measuring gas permeability after a balanced flow phase.

5. Expose the core to an overbalanced pulse with base drilling mud, including expected concentration of drill solids/mud solids for 5-60 min. The duration and magnitude of the overbalanced pulse depend on the type of drilling operation and potential problems expected.

6. Conduct a variable drawdown pressure return permeability test with gas or oil to determine the threshold pressure required to mobilize any damage induced by the overbalanced pulse. Ascertain if damage is reduced by increasing drawdown pressure. Determine the final amount of damage remaining at the maximum expected drawdown pressure. If the damage is severe, potential stimulation treatments could be evaluated at this time.

This procedure provides a good indication as to whether countercurrent imbibition effects will be problematic and how much underbalance pressure must be maintained to minimize their effect. This test can also provide an indication of the severity of formation damage and depth of invasion expected if the underbalanced condition is compromised. The test will also indicate the ability of formation pressure (or stimulation treatments) to remove the damage.

Overbalance evaluation

1. Core procurement and initial permeability measurements are identical to those described for the underbalanced lab tests.

2. Conduct an overbalanced drilling fluid test by circulating actual field-quality mud (containing drill and mud solids and bridging agents) in a turbulent fashion across the core face at the maximum expected overbalance pressure. Observe fluid loss rates, filter cake buildup and sealing potential, and depth of filtrate and solids invasion.

A spectrum of muds, from common conventional systems to sophisticated polymer blends with specialty sized bridging and fluid loss agents, may be evaluated to obtain the optimal system for overbalanced operations.

3. Conduct a variable drawdown pressure return permeability test with gas or oil to determine the threshold pressure required to mobilize any damage induced by the overbalanced pulse. Ascertain if damage is reduced by increasing drawdown pressure. Determine the final amount of damage remaining at the maximum expected drawdown pressure. If the damage is severe, potential stimulation treatments could be evaluated at this time.

This test sequence illustrates how damaging a conventional overbalanced drilling program may be in comparison to either a well-executed or poorly executed underbalanced program from the proceeding test program. The test provides an indication if comparable or superior performance may be obtainable and less cost and risk from a specially tailored conventional drilling system in comparison to an underbalanced operation. Additional details on this type of test procedure are provided in the literature.5

Suitable reservoirs

Based on the information presented, certain types of reservoirs are more applicable for underbalanced drilling operations than others. Prime reservoir types where underbalanced drilling has been successful in the past include the following.

High permeability (1,000 md), consolidated, intercrystalline sands and carbonates
At high formation pressures, well control issues may limit the utility of underbalanced drilling because of surface processing and handling issues.
High permeability, poorly consolidated sands
Some operations have risk of well bore collapse, however, a number of underbalanced operations have been conducted successfully in unconsolidated sands. At high formation pressure, well control issues may limit the utility of underbalanced drilling because of surface processing and handling and sand production problems.
Macrofractured formations (fracture apertures generally greater than 100 m)
If the fracture aperture exceeds 1,000-2,000 m, some possibility of gravity-induced invasion in fractures on the bottom of the well bore exists at low underbalance pressures. At high formation pressures, well control issues may limit the utility of underbalanced drilling because of surface processing and handing issues.
Underpressured/depleted formations where conventional drilling would exert more than 7,000 kPa (1,000 psi) hydrostatic overbalance pressure
Formations containing significant concentrations of materials sensitive to water-based mud filtrate
Such materials include expandable clays (1%), deflocculatable clays (5%), anhydride, halite, etc.
Formations with severe potential incompatibility with base filtrates (emulsions, sludges, precipitates)
Dehydrated formations with subirreducible water or hydrocarbon saturations
These formations may be candidates for underbalanced drilling using the appropriate based filtrate to avoid countercurrent imbibition and phase-trapping problems (water for oil wet systems, and oil for water wet systems).

Warning flags

The following are warning flags for underbalanced drilling operations:

High pressure zones exhibiting high flow and control capacity
Large pressure pulses occurring because of pipe connections, mud-pulsed measurement-while-drilling logging, bit trips, bit jetting effects, local depletion effects at high drawdown rates, and uncertain knowledge of original reservoir pressure
Multiple reservoir zones at differing pressures
Excessive slug flow and liquid holdup in the vertical section of the well
Locations where supply or mechanical problems are likely
Use of water-based systems in dehydrated (low Swi) tight gas reservoirs
Air/gas drilling in low-permeability homogeneous sandstones or carbonates.

Underbalanced drilling, like any technology, has specific applications. Formations with uniform matrix qualities, average-to-low permeabilities, normal pressures, and an absence of potential rock or fluid incompatibilities can often be drilled and completed successfully at a lower cost with conventional drilling technology, if a proper understanding of reservoir parameters is obtained.

Only through careful reservoir characterization can it be determined which reservoirs are the prime candidates for viable application of underbalanced drilling technology to obtain a maximum return on investment.

Acknowledgment

The author thanks Hycal Energy Research Laboratories for the data base used to prepare this article and Maggie Irwin and Vivian Whiting for their assistance in preparing the manuscript and figures.

References

1. Crowell, E., et al., Use of Tracers to Determine Reservoir Conformance, paper presented at the First Annual Conformance Control Conference, PNEC, Houston, August 1995.

2. Crowell, E., et al., Using Petrophysical Properties to Determine Bypassed Pay Potential, paper presented at the First Annual Conformance Control Conference, PNEC, Houston, August 1995.

3. Mehta, R., et al., Flash Tests to Determine Combustible Limits for Underbalanced Drilling, paper presented at the Unitar Conference, Houston, February 1995.

4. Bennion, D.B., and Thomas, F.B., Underbalanced Drilling of Horizontal Wells: Does it Really Eliminate Formation Damage? Society of Petroleum Engineers paper 27352 presented at the SPE International Symposium on Formation Damage Control, Lafayette, La., Feb. 7-10, 1994.

5. Bennion, D.B., and Thomas, F.B., Recent Investigations Into Formation Damage in Horizontal Wells During Overbalanced and Underbalanced Drilling and Completion Procedures, paper presented at the 2nd Annual Conference on Emerging Technology--Coiled Tubing--Horizontal Wells--Extended Reach and Multilaterals, Aberdeen, June 1-3, 1994.