Use of formate-based fluids for drilling and completion

Formates strong in HTHP, slimhole, coiled tubing;
chemical recovery critical to cost efficiency

John H. Hallman
OSCA, Forbrico

Formate brine systems were developed in the late 1980's and early 1990's by Shell Research KSEPL, The Hague, as high temperature fluids for drilling and completion. Since that time, many additional benefits have been found for the fluids, and by 1994, the fluids were considered ideal as the base for completion and drilling fluids for a variety of demanding environments.

The various formate brines (sodium, potassium, and cesium formate) have been subject to a variety of test regimes by major operating and service companies, as well as environmental testing facilities, and are quite possibly the most tested new drilling fluids today.

Early acceptance of the fluids was hindered by lack of availability and service, though Shell and Statoil both used formate systems successfully. With the emergence of Forbrico as a commercial distributor and service agent for the formates, it is expected that widespread use of these system will soon occur.

The true value of a fluid system can never be fully predicted on the basis of laboratory data alone, no matter how thorough. There is no substitute for field experience, to confirm or deny the predicted performance, and to discover previously unknown qualities, both good and bad. This paper will summarize several uses of the formate fluids in applications and document the first reclamation of a whole formate mud system.

Formate benefits

Formate brine systems have been found in a variety of laboratory studies to possess a number of beneficial characteristics relating to oil and gas drilling and completion (see accompanying table).

These benefits were largely predicted based on physical characteristics of the brines: monovalent composition, low crystallization temperatures, high transition temperatures of polymers when mixed in the brines, low water activity and osmotic effect on shales, etc. It remained for the operating companies to confirm these performance advantages in actual use. We will consider here the three main performance areas: temperature stability, low formation impairment, and good hydraulics from the low solids formulations.

The remainder of the predicted benefits (shale stability, compatibility with elastomers, low corrosion, etc.) were either indirectly confirmed because no problems related to these areas were experienced, or remain to be confirmed through additional uses.

Low formation impairment

In one of the first formate uses, Norske Shell drilled a number of horizontal wells in the Draugen Field (Norway) in 1993, using a sodium formate/Shellflo-S fluid at 9.6 ppg on these short (about 240 meters) horizontal sections. Pre-project testing on actual field cores indicated that the formate system would show increased reservoir core permeability to oil when this system was used.

Shell also selected the fluid based on environmental acceptability and shale stabilization. The formula consisted only of the formate brine, the Shellflo-S succinoglycan viscosifier, a low vis PAC, and sized calcium carbonate. Fluid properties during the drilling operation were as follows: density - 9.6 ppg; plastic viscosity - 14-25; yield point - 13-16; gels (10/10) - 5/6; API fluid loss - 2.8A.2 ml/30 min; and pH - 9.0-9.5.

The drilling results were excellent. The fluid system mixed easily and maintenance required only small additions of fresh water and the fluid loss polymer. The low solids composition allowed the horizontal sections to be drilled in less than 24 hours, because of low pressure losses and good hole cleaning. The PI on the well was considered an excellent 2,305 cu meters/bar/day, and well production was 48,000 b/d.

The cost of the system, compared to a KCl/polymer mud, was considered to be high, but roughly a third of this was from the Shellflo-S, and the price difference was more than offset by the short drilling time and large productivity of the well.

The sodium formate system increased drilling performance, and resulted in an extremely productive well. Higher fluid cost was offset by improved production.

High temperature slimhole

Temperature stability of polymers in brine-based drill-in fluids has traditionally been a drawback of these systems. Most brine-based fluids, particularly calcium-based fluids, will not properly hydrate biopolymer viscosifiers and fluid loss agents, or if they do, will not maintain adequate fluid properties over a sufficient period of time at temperatures over 250°F, and in many cases over 200°F. This drawback has prevented the use of these systems in applications where their non-damaging properties could be a benefit.

Formate brines are known as high temperature fluids. In fact, this property was the primary reason for the initial development of formates by Shell Research, who were seeking high temperature slimhole fluids. A large amount of research data backs up the stability of xanthans, succinoglycans, and various starches and PACs in the formates. Studies of transition temperatures of polymers in various formate brines indicated loss of viscosity or efficacy at temperatures only exceeding 375-400°F. Actual operating maximums, which of course are lower, were predicted to be 320-350°F. It was not, however, until late 1995 that the first actual field use of a formate drilling fluid was used in these high temperature environments.

Mobil Oil Germany had been drilling high temperature, slimhole gas wells in low permeability sandstone in the Walsrode Field with KCl/gel/carbonate fluids, with good success. Because of the long time needed to drill these wells (5-6 months typically), they were interested in trying a potassium formate-based system, because of the low solids content and polymer stability under high temperature.

The operator hoped that better hydraulics and hole cleaning, coupled with the predicted stability of the formate system, could increase rate of penetration and decrease maintenance costs. The potassium formate used was supplied by Forbrico and was incorporated as part of a Flo-Pro system from M-I Drilling Fluids.

Well conditions were as follows: interval depth - 5,110-5,510 meters total depth (TVD - 4,520-4,750 meters); interval length - 400 meters; hole angle - 59°; bottomhole temperature - 325°F; average bottomhole temperature (BHCT) - 135-140°F; required SG - 12.9 ppg.

Potassium formate application

The well was spudded in August 1995, with the potassium formate system used once the producing horizon was reached. After displacing to a 12.7 ppg formate Flo-Pro system, the interval was drilled successfully in 42 days. In spite of the high temperatures, small hole diameter, and the presence of shale in the formation, the fluid performed exceptionally, especially when compared to the previous wells that were drilled in the same area.

The fluid properties of the potassium formate system were very stable during the drilling operation, with values as follows: fluid density - 12.8 ppg; plastic viscosity - 18-22; yield point (lb/100 sq ft) - 26-36; gels (l0 sec/l0 min) - 9/13; pH - 9.4-9.7; API fluid loss (cc/30 min) - 1.5-2.0; and HTHP fluid loss (cc/300°F).

The major benefits from the use of the potassium formate system were:

Fluid maintenance costs were reduced by 75%, compared to the offset wells, because of the fluid's resistance to degradation of the polymers by oxidation or solids contamination.
Rates of penetration were increased by 50%, and circulating pressures lowered by 30%, because of the low solids formulation of the potassium formate Flo-Pro system, and the natural friction reduction of brines with biopolymers.
Formation clays were inhibited by the low water activity of the near-saturated formate, and the presence of the potassium ion.
Sticking coefficients were extremely low, and the filter cakes formed were very thin and tough, characteristic of lab experiences with formate mud systems.

The used potassium formate fluid was saved for recycling and future use. This well proved to be a highly successful test of the potassium formate system. Mobil, as well as the other German operating companies, plan further use of the formate fluids for these demanding environments.

The potassium formate system proved superior to previous fluids used for drilling the producing interval on this well. The low solids formula enhanced rate of penetration and decreased circulating pressure, and the fluid properties remained stable even at the high temperatures.

Coiled tubing drilling

Shell Expro drilled a sidetrack well on the North Cormorant Field (Well CN-3 1) using coiled tubing and a potassium formate-based drill-in fluid. The fluid was prepared and run by Schlumberger Dowell (Aberdeen), with the base potassium formate supplied by Forbrico.

Shell was seeking a low solids, non-damaging fluid with good hole-cleaning properties, and temperature stability at the bottomhole (BHST) of 266°F.

Shell conducted preliminary flow tests using a Dowell formulation through 12,500 ft of 2-in. coiled tubing (see accompanying table). The fluid was judged highly acceptable to use to attain sufficient flow rates, and stay well within operational parameters for the coil and equipment. At this writing, the window had been milled successfully, and the drilling operation was proceeding smoothly in the horizontal section, with reported rates of penetration several times higher than similar wells.

Reclamation

Being able to reuse and/or reclaim drilling fluids is important to their economics of use, especially with the premium fluids required for the demanding environments encountered in today's drilling. A fluid that can only be used once is charged at a full selling price. This increases costs for the customer and brings in disposal and other charges that increase the cost of drilling, significantly in some cases.

When a fluid can be re-used and reclaimed, it provides the end-user the benefit of lower costs; the supplier saves the cost of new product by reusing the old product, and passes the savings on to the end user. This allows options such as leasing and buyback of fluids, which reduce costs for the end user as well as streamlining the budgeting and AFE process. In some uses, almost all the fluid can be returned and reused, and only the small amount of lost fluid is purchased.

Brine completion fluids have been reclaimed for a number of years. This technology is well established. Low-density fluids are generally not reclaimed since they are very cheap to begin with. Higher density clear brines, usually those over 11 lb/gallon or so, are regularly treated and reused to increase cost effectiveness. High density brines are more expensive than low density fluids, and if they were not able to be reclaimed, they could be prohibitive to use. Reclamation keeps these fluids affordable.

The practice of reclamation has been now applied to brine-based drilling fluids as well, though not all brine drilling fluids are reclaimable. Sodium chloride and calcium chloride based drilling fluids are usually disposed of, since they are inexpensive for the most part and highly laden with solids that make reclamation more difficult and less efficient. Higher density calcium-based systems can be reclaimed, though their use has been only in recent months, and the reclamation procedures are not tested or established.

Formate brines are claimed to be highly reusable and reclaimable, and this re-use feature will contribute heavily to the economics of using formates for drill-in fluids. While sodium formate is relatively inexpensive, potassium formate is in the price range of some premium synthetic oil-based fluids. Cesium formate, while a strong technical choice in the higher density range, is an order of magnitude in price higher than potassium formate. It is obvious that the widespread use of the formates will only occur if the reclamation of these systems is efficient.

Recently, the first reclamation of a whole formate field mud was performed in Norway, in a demonstration of a laboratory-tested process on the formate fluids, developed and patented by Shell Research. The potassium formate-based drill-in fluid reclaimed was used in the drilling of the Gullfaks C-25 well by Statoil. The use of the mud system in a similar well, C-18, is well described in a previous paper (SPE 29409).

Reclamation method

The general procedure outlined by Shell Research, and followed by Forbrico and Norsk Hydro for the reclamation, is based on a pH adjustment to precipitate the solids, polymers, and other contaminants in the mud system, followed by a filtration separation to produce a clear fluid product. The steps involved were:

Formic acid is added to the whole mud to lower the pH of the fluid, and to partially dissolve the calcareous filter cake material in the mud. Calcium carbonate is a typical ingredient of the formate mud composition, or it is added in small quantities if not present. The dissolved calcium can help to flocculate the polymers during the pH adjustment.
A suitable base, potassium hydroxide in this case, is added to raise the pH of the system to about 13. While several bases can be used successfully, it was decided to use materials that serve to regenerate potassium formate (formic acid and potassium hydroxide). This action avoids unnecessary introduction of foreign material, and helps to maintain the density of the fluid during reclamation. During this pH increase, the fluid turns a darker color, and the polymers and solids flocculate, allowing separation.
The resulting suspension is filtered by means of a centrifuge or filter press, or combinations of the two. The filtrate product is a clear potassium formate brine.
The resulting clear brine can then be adjusted in composition and density by the addition of solid potassium formate, higher density potassium formate brine, or by evaporation, if desired.

The actual formate mud used in this reclamation test contained, in addition to the base potassium formate brine, a biopolymer, synthetic fluid loss polymer, sodium chloride, and Micromax, a form of manganese tetraoxide weighting agent. The specific gravity of the system was 14.35 ppg, with a solids content of about 28%. A centrifuge was not used, but instead the fluid was filtered through a scaled down diatomaceous earth filter press, of the type and design normally used in brine filtration. Five batches of the formate mud were treated and filtered separately in order to determine consistency, and to test the addition of a small amount of diluent to reduce solids content.

All five test batches were successfully reclaimed to clear brine in a single step following the process. The polymers and solids were efficiently removed, and contaminant soluble ions were also significantly reduced. Various aspects of the process follow:

Reclamation efficiency: The recovery of the formate brine varied across the different batches, depending on conditions. The recovery efficiencies (based on potassium formate fluid) for the five batches are 67.9%, 73.3%, 81.5%, 80.5%, and 80.1%.
All tests were run at room temperature conditions. Although based on bench tests, it is felt that increased temperature will increase the recovery efficiency by accelerating the flocculation reaction. The first two batches were run without any dilution of the whole mud. With the relatively large amount of solids present, it was decided to slightly dilute the mud with clear potassium formate brine to reduce the solids loading below 10%. This step increased the recovery efficiency significantly on the last three batches, and the fluid system was easier to pump as a result.
Soluble ion removal: During the normal drilling process, calcium, iron, and other contaminants such as barium can be introduced to the formate systems. While these contaminants do not pose any functional difficulties or reduce the formate performance at typical levels, it is desirable to remove divalent ions to avoid cycling up or concentration of these ions as the fluids are re-used and reclaimed several times. During the reclamation process, 21 different species were monitored both before and after the process. Most were present in low or nonexistent levels (see accompanying table).

The high pH generated during the reclamation process serves to precipitate many divalents as their hydroxides, leading to a good removal efficiency in the filtration phase. This shows that even during high reuse of the formates, divalent ions should remain far below levels that might cause any performance differences.

The high sodium level in the whole mud was the result of the addition of sodium chloride in the mud formulation, and should not be expected in a typical potassium formate formula. Blends of sodium and potassium formate, of course, will have high sodium levels, but do not affect performance, since this is an intended use of the formates.

The formate brines, when formulated as drilling or completion fluids, are highly reclaimable for better cost effectiveness. A pH adjustment followed by filtration produces clear formate brine at 70-80% efficiencies from whole mud. Divalent ions are easily removed from both drilling and completion fluids.

Acknowledgment: The author thanks the following for their assistance: Forbrico, OSCA, Hydro Chemicals, KSEPL (Shell), Schlumberger Dowell, and M-I Drilling Fluids.

This paper was presented at the New Oilfield Chemical Technology Conference, held on March 29, 1996 in New Orleans. References are available from the author.