Underbalanced foam drilling reduces hole problems and costs

Robert R. Teichrob, James J. Manuel
Tesco Corp.
Calgary

The use of foam in underbalanced drilling has reduced hole problems and provided substantial cost savings by improving cuttings removal and increasing overall penetration rates.

Underbalanced drilling (UBD) has proven to be a viable and economic method to drill the pressure-depleted Jean Marie formation in Northeast British Columbia. Drilling fluid blends have evolved over the last 3 years from fresh water/nitrogen to foam.

The liquid phase has evolved from straight water to slightly polymerized mixtures to concentrated, nitrified viscous slugs to foam.

Drilling Program

The advancement of horizontal drilling technology has provided an opportunity to open more pay to the well bore. Because it was assumed that fracture flow was the primary inflow mechanism in the field, it was necessary to understand fracture orientations in the Jean Marie formation and to maximize the probability of intersecting fractures.

The Jean Marie formation is the lowest member of the Redknife formation. It is underlain by shales of the Fort Simpson formation and overlain by shales and carbonates of the Redknife formation. It is an under-pressured, laterally continuous platform and shelf carbonate covering a large portion of Northeast British Columbia, with substantial coverage in the adjacent areas of Alberta and the Northwest Territories.

It normally ranges in thickness from 12 to 20 m (39.4 to 65.6 ft) and is characterized by inter-crystalline, pinpoint, and vuggy porosity which was enhanced through leaching. The permeability was increased by the presence of subvertical natural fractures. A typical range for matrix permeability is 1-3 md. However, permeabilities can attain several hundred md within zones of natural fractures. The typical porosity range is 6-10%.¹

With the development of UBD technology, Ranger Oil Ltd. was able to realize immediate savings with regards to lost drilling fluids, ultimate well bore length, associated drilling time, and completion costs. More importantly, questions regarding inflow mechanisms were answered.

Monitoring production while drilling clearly showed constant, modest inflow rates interrupted by massive, instantaneous inflow rates when fractures were encountered.2 As more hole was drilled, inflow rates increased slightly, confirming that the increased drawdown at the point source resulted in increased production.

Under normal drilling conditions using liquids, production inflow is often unnoticed, and in most cases more hole is drilled than is necessary. However, production inflow while drilling underbalanced is immediately noticed, and case histories show that section lengths have been shortened by as much as 80%.

Well bore configuration

In 1995, the first UBD wells were drilled into the Jean Marie formation. Although drilling methods have evolved, well bore and drillstring configurations have remained the same. The normal configuration consists of a 177.8 mm (7 in.) intermediate casing string set through a high-radius build section. This casing is landed at the top of the Jean Marie formation at inclinations near 90°. The open hole section is then drilled out with a 156.0 mm (6.1 in.), tricone bit (5-1-7) using a standard 121.0 mm (4.76 in.) bottom hole assembly with 101.0 (3.97 in.) mm drill pipe and heavy-weight drill pipe.

During 1997, bottom hole pressures (BHPs) were recorded real time in order to monitor downhole underbalanced conditions. This information confirmed the accuracy of the foam model. In addition, logging-while-drilling gamma ray tools were used for two of the wells which provided information for purposes of geosteering.

Drilling and completion techniques

The initial drilling objective was to achieve underbalanced conditions using a water/nitrogen mixture for the circulating fluid. The density of the fresh-water liquid phase was decreased by injecting a nitrogen-gas phase. This worked well in achieving a bottom hole circulating pressure that was less than the formation pressure. The system was acceptable with regard to reservoir considerations, but not optimal with regard to drilling considerations.

Initial completion strategies used endless tubing units that washed and squeezed the entire lateral section with a solution of 10-15% hydrochloride prior to running production tubing. Unfortunately, identifying the part of the well bore section which would respond favorably to the acid wash was virtually impossible. Field observations consequently showed that marginal underbalanced wells did not exhibit appreciable production increases as a result of subsequent washes and squeezes.

It was found that the full-cycle costs to drill and complete the Jean Marie formation underbalanced were comparable and sometimes less expensive than horizontal wells which were conventionally drilled and completed.

Lessons learned

Initial underbalanced programs utilized a mixture of fresh water and membrane-generated nitrogen which was pumped at various rates and ratios. The optimal liquid/gas ratios and rates were interrelated with hole cleaning, effective rate of penetration (ROP), and sample size.

Inadequate liquid rates would almost always result in sticky hole conditions which could very rapidly result with a stuck drill. A decrease in the ROP was needed to allow the well time to clean itself up prior to the next connection.²

Inadequate gas rates would negatively affect the positive-displacement motor resulting in mud-motor stalling. The relationship between efficient hole cleaning and effective penetration rates indicated that a viscosified aqueous phase would contribute positively to the overall ROP.

In order to do so, viscosity sweeps were used. A separate fluid holding tank filled with a viscosified water (guar) was mixed, and the fresh-water injection stream was switched to viscosified water 10 min prior to kelly down. Theoretically, viscous sweeps would yield larger cuttings at the surface and result in better hole cleaning. However, no change in effective hole cleaning was noticed and the new viscous effects of the fluid were difficult to reconcile and model with the multiphase flow software.

The additional operational complexity of mixing viscous sweeps did not result in improved hole cleaning, so it was decided to go back to fresh water drilling using membrane-generated nitrogen pumped at rates and ratios consistent with hole geometry and observed production.

Survey techniques

Conventional positive or negative-pulse survey telemetry is not viable because of the presence of a gasified drilling fluid. Pulse-telemetry requires almost a pure liquid phase in order for data to be sent to the surface. To overcome this problem, both wire line and electromagnetic (EM) conveyed survey data systems have been utilized. Each system works well, although they have physical and economic constraints.

Currently, the EM measurement-while-drilling (MWD) tool has limited availability. In general, the functionality of the EM-MWD technology is constrained by the presence of highly resistive formations (salt or anhydrite) and minimum fluid throughput.

Hole cleaning

Increased penetration rates are often obtained when drilling underbalanced. Lower BHPs allow higher instantaneous penetration rates. However, higher overall penetration rates can increase the bottom hole circulating pressure and may result in overbalanced conditions. In addition, inadequate hole cleaning can cause hole pack-off resulting in stuck pipe. Annular fluid segregation is predominantly responsible for both of these phenomena.

Whenever fluid circulation is stopped, annular fluid segregation can occur. Gas tends to rise to the surface while the liquid settles to the bottom of the hole. The resulting liquid slug may cause increased BHPs when fluid circulation is reinitiated. The pressure of the injected fluid will rise until the liquid slug begins to move up the annulus. The volume of this slug will determine the magnitude of the pressure increase.2

In addition to BHP concerns, hole cleaning may also be affected. High penetration rates generate large volumes of cuttings which may not be efficiently removed from the lateral section until the bottom hole fluid-slug begins to move. Penetration rates must be controlled to ensure proper hole cleaning and slug removal.

Water/nitrogen systems can also cause additional hole drag on gas wells, and lateral sections greater than 750 m tend to experience directional control problems. Orienting becomes difficult when excessive hole drag prevents the transfer of weight to the bit. This is because of the drying effect of gas on the well bore.

Benefits of foam drilling

Foam drilling systems can alleviate problems associated with water and nitrogen circulating systems. Hole cleaning problems are minimized because the foam system has superior cuttings entrainment and transport properties. Annular fluid segregation is minimized because the foam system helps to hold the liquid phase in suspension, preventing the liquid from forming a large slug at the bottom of the hole.

Hole drag is minimized because foam provides additional lubricating properties in addition to holding the gas within the foam solution. This may allow for incremental lateral section reach.

In is necessary to maintain a stable foam at elevated BHPs and temperatures. Then the system will provide faster overall penetration rates than water/nitrogen systems. The bit will not drill faster with foam; however, cuttings and fluid removal will be more efficient, allowing higher penetration rates to be consistently maintained. Connection times are also reduced because circulation time is miminized prior to breaking the joint.

The foam system not only removes cuttings from the well bore more efficiently, but it also holds the cuttings in suspension when circulation is stopped. This has two important effects. First, cuttings in the vertical section of the well bore are prevented from falling back to the bottom of the hole. Second, cuttings in the lateral section do not settle to the low side of the bore hole.

Cuttings that settle to the low side of the hole are finely ground by the action of the drillstring. Thus, superior samples can be obtained when drilling with the foam system. Large, angular cuttings are lifted to the surface quickly rather than being ground into the smaller, rounded samples that are commonly encountered when using a water/nitrogen system. In addition, the large cuttings are more representative of the formation and greatly simplify the well site geologist's work.

Cuttings that settle in the vertical section of the well bore can result in longer connection times because it is necessary to circulate them up in order to keep the hole clean. This is especially true if fluid-slugs form during connections. It is important to ensure that the fluid-slug is moving before the bit generates new cuttings.

This can be accomplished by circulating after a connection or by closing the annulus during the connection. Closing the annulus will help to keep the fluid energized so that it begins to move shortly after reinitiating circulation. It will also help to minimize fluid loading from the formation.

The foam system will then allow faster drilling because of superior hole cleaning and minimal annular-fluid segregation as opposed to allowing the bit to drill faster. Foam stability must be maintained, but it is often difficult to determine which parameters need to be adjusted. Real-time BHP gauges should be used because they can provide warning signs that foam stability has been compromised.

A foam model may be used to provide evidence that foam stability has been achieved, especially if it calculates pressures which are in line with real-time gauge pressures. Gauge pressures which are more closely related to multiphase flow models suggest that the foam stability has been compromised. Foam instability will initially result in gauge pressures which are lower than predicted. This is because of the smaller friction losses associated with the multiphase flow system.

Gauge pressures will rise above predicted pressures as hole cleaning is compromised and fluid loading occurs. This is revealed at the surface in the form of degrading formation samples and fluid-slugs coming from the well bore.

Foam allowed the Jean Marie wells to be drilled faster. (Fig. 1) [25,794 bytes] shows a comparison of average drilling rates for 14 wells drilled since 1995. The total time from drillout to total depth (TD) includes trips, connections, and repair time. Average drilling rates for the nitrogen/water and foam systems were 3.5 and 8.2 m/hr, respectively.

In addition, drilling rates were determined for a 48-hr period (Fig. 2) [25,148 bytes]. Average drilling rates for the nitrogen/water and foam systems were 5.1 and 10.1 m/hr, respectively, and excluded trip and repair time. This confirmed that drilling with the foam system allowed overall penetration rates approximately two times higher than the nitrogen/water system.

The average penetration rates were used to determine the number of days required to drill a 750 m lateral section using both circulating systems (Fig. 3) [13,256 bytes]. The section would have taken 3.8 days to drill using the foam system while it would have taken 8.9 days for the nitrogen/water system. Superior hole cleaning associated with the foam system allows for the sustained high rates of penetration.

Thus, substantial cost savings and reduced hole problems suggest that foam drilling is preferable over nitrogen/water systems.

Foam behavior

Foam is defined as a large volume of gas dispersed in a small volume of liquid containing a foaming agent (surfactant). The external or continuous phase is liquid and the internal or noncontinuous phase is gas. The interaction that occurs between the gas bubbles is the mechanism that creates viscosity.

Polymer added to the liquid phase increases stability, rheology, and fluid loss properties. A stable foam maintains the dispersion of the gas bubbles in the liquid medium.

Foam stability is affected by:

• Polymer type
• Polymer loading or concentration
• Surfactant type
• Surfactant loading or concentration
• Foam quality
• Mixing energy.

A measure of foam stability is referred to as "half-life." The "half-life" of a foam is a qualitative measurement and is the time required for one half of the liquid-phase to break out of the foam at atmospheric conditions. Foam fluids are characterized by their "quality." Foam quality is a calculated percentage based on the ratio of gas volume to the total fluid volume (gas and liquid).

Quality is defined as Q = v_g/( v_g + v_l), where: Q is quality in %, v_g is the volume of the gas phase, and v_l is the volume of the liquid phase. An acceptable quality range for a stable foam is 53-96%. If the quality falls outside of this range, segregation between the gas and liquid phases will occur. The foam can invert to a mist if too much gas is present, or into an energized fluid if too much liquid is present. In either case, the rheological and fluid loss properties of the foam are lost.

In a UBD application, knowledge of the foam's characteristics under downhole conditions is important. The removal of cuttings and well bore fluid is necessary to prevent annulular loading and the subsequent increases in BHPs. Therefore, quality calculations are based on the volumes of gas and liquid at bottom hole conditions.

The liquid is assumed to be incompressible. However, the amount of space occupied by a gas changes with pressure and temperature. A cubic equation of state is used to calculate an equivalent downhole gas volume, and this number is used in the quality calculation. The downhole foam quality will be in error if gas injection rates are adjusted based on calculations using surface pressures and temperatures.

The flow characteristics of a foamed fluid can be determined by analyzing frictional losses in the well bore. Foam frictional losses are greater than those of the base fluid alone. If frictional pressure losses are lower than expected, this becomes an excellent indicator that the foam stability is poor. The problem can then be attributed to a mixing problem or incorrect surfactant loading.

Foam generation is easily achieved under turbulent flow conditions with the correct surfactant concentration; however, turbulent flow may not be achieved at lower pump rates. A foam generator is required if the friction pressure indicates that the foamed fluid may be in laminar flow and mixing is not sufficient.

A foam evolves through three distinct flow regimes with increasing quality. The first foam regime ranges from 0 to 52% quality. It acts like a Newtonian fluid because there is insufficient interaction between the gas bubbles to increase the viscosity. This is classified as an energized fluid.

The second regime begins when the quality achieves 53%, from where the foam becomes stable. Past this point, the viscosity and stability increases with quality until it reaches 96% gas by volume. Stable foams have the same yield point as Bingham Plastics; however, this only affects foam characteristics at very low flow rates. The foam can be effectively modeled as a Power-Law fluid while in this quality range.

Finally, as the foam increases beyond 96%, the foam inverts and becomes a mist. In this regime, the base liquid becomes the noncontinuous or internal phase and the gas becomes the continuous or external phase. These fluids are classified as atomized fluids.

Solids-carrying capacity

The effective viscosity of a foam increases with foam quality. A drill cutting can be 5-10 times as large as a gas bubble in the foam. For the cutting to fall through the foam, it must overcome the differential interfacial tension between the bubbles. Under dynamic conditions, this falling process is very slow and the settling velocity is slow. Low settling rates allow for very good carrying capacity and excellent hole cleaning during drilling.

The addition of polymers to the base fluid of a foam will enhance stability and rheological properties. However, to break a very stable foam, breakers or a demulsifier may be required. Foam fluids have limitations and the stability can be affected by a number of materials which should be avoided including:

• Antifoam agents/defoamers
• Hydrocarbons (as additives)
• Heavy brines (formation brines 2% salt)
• Alcohols
• Mutual solvents.

Foaming agents can normally tolerate contaminants in the aqueous phase of less than 3% by volume. Compatibility testing of all additives and any potential produced fluid should be done prior to drilling to prevent any surprises.

Modeling

Modeling a foam system under dynamic conditions is difficult. Many assumptions are made during input stages that can have detrimental affects on the calculated output. A new foam model was introduced to the project in 1997. Previously, multiphase flow models were used to simulate the system. Both models are calculation intensive and consider reservoir production when determining well bore pressure profiles.

The foam model has proven to be very accurate if input values are correct. There are some basic parameters and assumptions that need to be correctly inputted in order to prevent erroneous results. The foam quality must be calculated at downhole conditions because of the compressibility of gas. Any changes to surface pumping rates based on an incorrect quality can be disastrous.

All gas production is assumed to "tie-up" as much liquid as is required to satisfy the specified quality. If more liquid is available in the system than is required, the model will indicate multiphase flow conditions with the presence of free liquids. Liquid production from the reservoir is incorporated into the liquid phase.

The accuracy of both models has been confirmed during the 1997 drilling program. Real-time downhole pressure gauge data were available and allowed us to get instantaneous downhole pressures to compare with model predictions. A change in foam stability was indicated by a drop in the BHP and was confirmed by running the multiphase model.

Stable foams have much higher frictional losses than multiphase fluids. Both models were extremely accurate under steady state conditions.

A model is a tool and should be used as only an indicator. If actual data do not correspond with predicted values, further investigation is required to determine why. The model will not tell you what the problem is, it will only indicate that a problem exists.

Acknowledgments

The authors would like to thank Czar Resources Ltd., Ranger Oil Ltd., the management of Reservoir Drilling Services (RDS) of Tesco Corp., and Abid Rashid of RDS for their assistance in preparing this article.

References

1. Hamilton, W.D., Van Alstine, D.R., Butterworth, J.E., and Raham, G., "Paleomagnetic Orientation of Fractures in Jean Marie Member Cores from NE British Columbia/NW Alberta," The Petroleum Society of CIM, paper 95-56, May 14-17, 1995.
2. Butler, S.D., Rashid, A.U., and Teichrob R.R., "Monitoring downhole pressures and flow rates critical for underbalanced drilling," OGJ, Sept. 16, 1996, pp. 31-39.

The Authors