Drill-in fluid reduces formation damage, increases production rates

Nick Hands
Nederlandse Aardolie Maatschappij B.V. (NAM)
Velsen, The Netherlands

Kevin Kowbel
Ensco International/NAM
Assen, The Netherlands

Sven Maikranz
M-I LLC
Houston

Robert Nouris
M-I LLC
Velsen, The Netherlands

A sodium formate drill-in fluid system reduced formation damage, resulting in better-than-expected production rates for an offshore Dutch development well.

The highly successful completion of a subhorizontal development well clearly illustrates the tremendous impact a properly formulated and engineered drill-in fluid can have on the drilling and completion phases of a borehole.

Programmed to optimize production capacity and reservoir drainage from a Rotliegend sandstone gas discovery, the 5 7/8-in. subhorizontal production interval was drilled and completed barefoot with a unique, rheologically engineered sodium formate drill-in fluid system.

Production rates achieved 2.1 million cu m/d (110 bar), compared to predicted production rates of 1.5 million cu m/d. The 880-m (2,880 ft) section was drilled in only 12 days, 8 days ahead of schedule. Furthermore, contingent acid stimulation was not required.

The novel sodium formate system was chosen after Nederlandse Aardolie Maat schappij B.V. (NAM) evaluated several alternatives to the water-base and low-toxicity oil-based mud systems employed through the producing zones of earlier wells.

The new system, consisting of a sodium formate (NaCOOH) brine as the base fluid and properly sized calcium carbonate as the formation-bridging agent, was selected on the basis of its well-documented record in reducing solids impairment and formation damage in similar sandstone structures in Germany. The system was engineered around the low-shear-rate viscosity (LSRV) concept, designed to provide exceptional rheological properties.¹

Drill-in fluid selection

Drill-in fluids are classified as either solids-free ² or minimal solids systems. Generally, drill-in fluids designed specifically for production zones are those that provide a kill-weight density with a minimal amount of solids.

The solids content is limited to bridging agents, which plug pore spaces at the bore face, thereby restricting the invasion of solids and fluids into the formation. Nondamaging bridging agents must be sized to formation properties and comprise either acid-soluble calcium carbonates or water-soluble salt crystals.

The nondamaging characteristics of both the bridging agent and the fluid system itself are particularly critical when completing horizontal reservoirs open-hole.³ Open-hole completions, which can only be employed in well-consolidated rocks where the possibility of hole collapse is minimal, provide good access to the formation and filter cake, thus simplifying clean-up and stimulation treatments.

However, the absence of zonal isolation increases the likelihood of formation damage. Consequently, the bridging properties of the fluid must be selected so the D90 (90% of the particles are smaller than size x) of the particle distribution is about equal to the pore size of the rock (Fig. 1 [36,570 bytes]). If matched correctly to the pore diameter, bridging agents will minimize the influx of fluid and particles into the sandstone network.

When production is initiated, the filter cake is lifted off easily and does not restrict the flow of formation fluids. An accepted guideline for determining the pore throat size of the formation in microns is to consider the square root of the permeability of the targeted reservoir in millidarcys.³ This is used to determine the correct particle-size distribution of the bridging agents.

For the average sandstone reservoir, the pore size is often in the silt range, between 5 and 74 microns. Therefore, silt-sized particles from calcium carbonate and sized salt, are essential elements of a nondamaging drill-in fluid system.

Because cuttings transport and hole cleaning in high-angle and horizontal well bores becomes proportionately more difficult than in vertical wells, fluid rheological properties, especially the velocity/viscosity relationship, cannot be understated.

In an earlier study, it was concluded that basic rheological parameters, such as plastic viscosity, flow behavior index and consistency factor, have a direct bearing on penetration.¹ For drill-in fluids, the ideal viscosity is one in which the system develops "plastic-like" properties almost instantaneously.

This phenomena, referred to as LSRV, can more simply be defined as the thickness of a fluid at very low flow rates. For horizontal wells, this property in tandem with drill string rotation,⁴ instantly suspends solids in the mud flow path, while preventing cuttings from settling on the low side of the hole and significantly restricting the invasion of mud and filtrate in permeable formations.

Sodium formate drill-in fluids

The advent of formate brines as drilling and completion fluids has been well-documented. ^{5 6} Clear, high-density brines were first used as packer fluids in the late 1950s (OGJ, July 24, 1961, pp. 91-96). These brines have evolved into an entire suite of specialized salt solutions for placement across production zones and are used to prevent formation damage during drilling, completion, and workover operations.

More recently, ever-changing environmental legislation has made brines an acceptable alternative to both oil and synthetic muds, particularly in the completion phase of a well. Formate brines hold great potential as effective completion fluids because formates can provide densities up to 19.6 ppg (2.35 kg/l.) with no solid (undissolved) weight material.⁵

More specifically, because formates require no weighting material, completion systems can be designed to contain only the type and amount of particles desired. Consequently, no precipitation or divalent ion-induced damage occurs to the formation.

Generally, formate brines comprise formate salts of alkali metals that are very soluble in water, thus forming brines of extremely high densities.⁴ Three salts-sodium formate (NaCOOH), potassium formate (KCOOH), and cesium formate monohydrate (CsCOOHH₂0)-have been found to be the most effective drilling and completion fluids. Sodium formate is the least soluble of the three types and possesses a density limit of about 11 ppg (1.32 kg/l.).

Well plan

The subhorizontal development well was designed to maximize production capacity and optimize reservoir drainage from an area of the field with poor reservoir quality. The discovery well was drilled, completed, and tested in 1979 in the same area of the field. Despite perforating under drawdown conditions, followed by acid stimulation, this cased-hole completion failed to produce at commercial gas rates.

Critical factors for the success of the development well in the lower-quality reservoir were two-fold:

1. Maximize total kh (permeability x formation thickness): The 5 7/8-in. subhorizontal reservoir interval should intersect all laterally continuous sandstone layers and increase the chance of encountering potentially highly productive features, such as fractures.
2. Reduce damage skin: Because the operator intended to complete the reservoir open hole, it was critical to select a drill-in and completion fluid that would minimize formation impairment caused by the drilling and completion process.

Fig. 2 [40,038 bytes] illustrates the planned well trajectory. As shown, the kick-off point was in the 7-in. liner at 2,085 m. Because the kick-off point was in the 7-in. liner, the combination of high annular velocities and a short build section made hole cleaning less critical in this section.

The 5 7/8-in. production interval penetrated the Ten Boer claystone before entering the Upper Slochteren sandstone reservoir. The competent nature of the Rotliegend sandstone in this area meant the entire reservoir could be completed open hole. That would leave the reservoir interval exposed to the potentially damaging effects of the drilling/completion fluid for an extended period.

Further, the well plan and the associated high costs prohibited the use of perforations to bypass damage in the case of severe impairment. Consequently, it was imperative that the drilling and completion fluid be designed to minimize formation damage.

Drill-in fluid program

The water-based drill-in system selected for a trial on this well employed a sodium formate brine as the base fluid, calcium carbonate as the bridging agent, purified xanthan biopolymer as the rheology modifier, and a modified starch for fluid loss control.

The system itself was rheologically engineered for the targeted interval with a minimum solids content and designed around the desired LSRV, measured at a shear rate of 0.0636 sec^-1 using a Brookfield viscometer. As discussed earlier, an optimal LSRV is critical not only for effective hole cleaning and overall drilling performance, but also for minimizing filtrate invasion and ensuing formation damage. When monitoring the LSRV, the yield point is less critical than for other fluids.

Overall, the rheology of the system was characterized by elevated LSRVs, fragile gel strengths, and extremely low plastic viscosities, properties that measure the internal resistance to fluid flow. These properties are attributable to the amount, type, and size of solids present in a given fluid.

This behavior generates a very shear-thinning fluid while in motion. Once static, the polymer network of the fluid creates a solid-like structure that entraps the solids. When transported to the surface, the solids particles are then easily liberated because of the high shear rate induced by the shale shaker screens.

Maintaining minimal solids content is accomplished by adjusting the density with clear brines and using solids only as bridging agents for filtration control. Because of its unique rheological behavior, the sodium formate system reduces drag and pressure. When compared to conventional drill-in fluids, the high-LSRV sodium formate system achieves a 15-40% pressure reduction, as shown by significant improvements in the transmission of hydraulic energy to the bit. In this particular case, a pressure reduction of 33% was achieved.

Fig. 3 [49,040 bytes]compares the primary properties of the sodium formate system and the mineral oil-based mud used in previous wells. As shown, the low-solids content of the latest system was formulated to provide less fluid friction, while the low plastic viscosity (PV) promoted faster penetration rates at lower pump pressures.

In this system, a three-dimensional network of polymers forms the gel structure. The system is designed to build-up quickly with sufficient strength to suspend the solids, yet weak enough to break easily when circulation begins.

Drilling summary

NAM's team practice normally consists of drilling the reservoir sections with low-toxicity oil-based muds while running viscous/weighted sweeps as required to assist with cuttings removal. When drilling high-angle reservoir sections, most trips are made while back reaming, which further assists hole cleaning. The sodium formate drill-in fluid allowed for beneficial modifications to the standard drilling practice with positive results.

Because of the exceptional fluid properties, the drill-in fluid:

• Eliminated the need for pills to assist with hole cleaning
• Increased expected flow rates because pressure losses were reduced
• Reduced the need for backreaming out of the hole for hole cleaning purposes (maximum overpull during the three trips was about 2,200 lb)
• Achieved faster than expected penetration rates because increased flow rates enhanced turbine performance.

After running the 75/8-in. liner from 2,573 m (8,439 ft), NAM drilled to 2,602 m (8,537 ft) with a low-toxicity, oil-based fluid system, a positive displacement motor (PDM), and polycrystalline diamond compact (PDC) bit.

At that point, the open hole was displaced with the 10.6 ppg (1.27 kg/l.) sodium formate drill-in fluid and drilling continued to 2,676 m (8,780 ft). After drilling 102 m (335 ft) of Ten Boer claystone with a PDM/PDC configuration, at penetration rates of 3.2-20 ft/hr (1-6 m/hr), the operator changed the drilling assembly to an impregnated diamond bit/turbine combination.

Penetration rates immediately increased to 16.4-49 ft/hr (5-15 m/hr), well above expectations. The system generated very fine powder-like cuttings that easily separated from the mud through the 230/325-mesh screens and two hydraulic centrifuges. The higher-than-expected penetration rates remained consistent for most of the section, slowed only by clay stringers dispersed throughout the reservoir.

Following a second bit trip at 11,020 ft (3,360 m), the remaining section was completed uneventfully without spotting pills. Tripping proceeded without problems and the hole remained clean and in excellent shape. Although no drag was observed during the section, an under-gauged stabilizer gradually increased the torque.

Even with two bit trips, the 2,883-ft (879 m) section was drilled in 12 days, as compared to the planned 20-day program (Fig. 4 33,706 bytes]). Because of the exceptional hydraulics of the system, the flow rate was limited only by the downhole equipment and not the pump pressure.

In most of NAM's 5 7/8-in. hole sections, the maximum allowable standpipe rate was 195-250 gpm (750-950 l./min). Because the sodium formate system reduced frictional losses, flow rates were as high as 290 gpm (?1,100 l./min), restricted only by downhole equipment.

Completion summary

The well was completed barefoot and put on production without any stimulation or remedial work. A sodium/potassium formate brine was used as the completion fluid. Before arriving on the location, the brine was pre-filtered to 10 microns and filtered down to 20 NTU (nephelometric turbidity units) before displacing in the open hole. The formate brine was specially designed for true crystallization temperatures (TCT) below -10° C. (14° F.), without the use of chlorides. This was required because the production string was sensitive to corrosion.

In addition to the negative skin and increased production, the low-solids sodium formate system cleaned up more efficiently than the high-angle offset wells drilled with low-toxicity, oil-based mud systems.

Acknowledgments

The authors wish to thank the management of Nederlandse Aardolie Maatschappij B.V. and M-I LLC for permission to publish this article and Jim Redden of M-I LLC for preparing the manuscript.

References

1. Beck, F.E., Powell, J.W., and Zamora, M., "The Effect of Rheology on Rate of Penetration," presented at THE 1995 SPE/IADC Drilling Conference, Amsterdam, Feb. 28-Mar. 2, 1995.
2. Svoboda, C., "New Solids-Free Drill-In Fluid Enhances Horizontal Wells," American Oil & Gas Reporter, August 1996.
3. Stephens, M., "Selection of Non-Damaging Drill-In Fluids for Horizontal Wells," presented at 3rd Annual North American Conference on Emerging Technologies-Coiled Tubing and Horizontal Wells, Calgary, May 15-16, 1995.
4. Zamora, M., and Jefferson, D., "Hole Cleaning and Suspension in Horizontal Wells," presented at 3rd Annual North American Conference on Emerging Technologies-Coiled Tubing and Horizontal Wells, Calgary, May 15-16, 1995.
5. Howard, S.K., "Formate Brines for Drilling and Completion: State of the Art," presented at SPE Annual Technical Conference and Exhibition, Dallas, Oct. 22-25, 1995.
6. Downs, J.D., "Formate Brines: Novel Drilling and Completion Fluids for Demanding Environments," presented at SPE International Symposium on Oilfield Chemistry, New Orleans, Mar. 2-5, 1993.

The Authors