IADC/SPE 99068 Drilling and Completing Difficult HP/HT Wells With the Aid of Cesium Formate Brines— A Performance Review J.D. Downs, SPE, M. Blaszczynski, SPE, J. Turner, SPE, and M. Harris, SPE, Cabot Specialty Fluids
Copyright 2006, IADC/SPE Drilling Conference This paper was prepared for presentation at the IADC/SPE Drilling Conference held in Miami, Florida, U.S.A., 21–23 February 2006. This paper was selected for presentation by an IADC/SPE Program Committee following review of information contained in a proposal submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the International Association of Drilling Contractors or Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the IADC, SPE, their officers, or members. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the International Association of Drilling Contractors and Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 1.972.952.9435.
Abstract Conventional drilling and completion fluids containing weighting solids or hydrocarbons or halide brines can create problems with hydraulics, well control, well integrity and well productivity in HPHT operations. The negative influence of conventional fluids on drilling and completion operations can be sufficiently serious to compromise safety and degrade the economics of challenging HPHT field developments. Formate brines have been developed specifically to provide improved drilling and completion fluids that are free of the troublesome components found in conventional fluids and therefore better suited to meet the needs of oil companies involved in difficult HPHT well constructions. Formate brines have been successfully used as reservoir drill-in, completion, workover and suspension fluids in more than 130 HPHT well construction operations over the past 10 years. These applications have included 100 cases in which high down-hole pressures have necessitated the use of cesium formate brines for well control purposes. Some 15 applications of cesium formate brines to date have been HPHT reservoir drill-in operations in high angle wells where operators considered that conventional fluids could create a safety risk and adversely effect project economics. We review the published information on the field performance of the cesium formate brines in HPHT applications, and conclude that the novel benefits of the technology that were first promised some 15 years ago during the early product development phase have now been fully validated. Introduction The objective of the drilling and completion process is to safely deliver high quality wells that are optimized in terms of providing shareholder value:
- Best well productivity at lowest drawdown - Best well integrity and longest structural lifetime - Lowest well construction cost - Lowest environmental impact and liability exposure - Best reservoir information capture The choice of drilling and completion fluid used in a well construction operation has a critical influence on the extent to which an operator can meet this objective. In particular the fluid’s performance will play a significant part in determining whether or not an operator meets its key performance indicator targets in the following areas: - Time to drill and complete - Well control and safety incidents - Well integrity - Well lifetime and maintenance costs - Well productivity index - Waste management costs - Logging capability and interpretation - Environmental footprint and impact - Exposure to liability (short- and long-term) The drilling fluid chosen for the upper well sections must offer a host of functionalities: - Ability to maintain the integrity of weak rocks - Ability to minimize fluid loss into permeable rocks - Ability to provide stable well control - Ability to efficiently transfer hydraulic power - Ability to move cuttings to the surface - Provide steel/steel and steel/rock lubricity - Provide protection against all forms of corrosion - Allow formation evaluation - Pose little or no hazard to rig personnel - Have little or no adverse effect on the environment - Have little or no adverse effect on elastomers If the drilling fluid is to be used in reservoir sections without further intervention it must cause minimal change to the native permeability of the reservoir rock in the near wellbore area. The drilling fluid filtrate must also be compatible with other filtrates that might leak-off from subsequent cementing and completion operations. A completion fluid should have the same overall properties as a reservoir drilling-in fluid and, ideally, should be the same fluid minus any drilled solids. In the past these functionalities have been provided by surprisingly low-tech/low-cost fluid formulations based simply on slurries of barite particles suspended in viscosified oil or water containing halide salts (chlorides or bromides).
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The problem now facing the oil industry is that the process of economically extracting what remains of the world’s hydrocarbon reserves is stretching the traditional drilling and completion fluids to their performance limits and beyond. This is particularly true in the case of offshore HPHT field developments where the application conditions are extremely challenging and the required fluid performance demands are exacting. This paper examines how conventional drilling and completion fluids have been failing to fully meet the demands of difficult HPHT well construction. It then charts the development of formate brines as the new improved HPHT drilling and completion fluids, from their origins in Shell Research in 1986 through to the present day use of cesium formate brine in North Sea and Gulf of Mexico. Our review of the published information on the field performance of the cesium formate brines in HPHT applications draws us to conclude that the benefits of the technology that were first promised some 15 years ago during the early product development phase have now been fully validated. Problem definition Modern HPHT drilling conditions can expose the inherent design failings of conventional drilling fluids1. The high loading of barite in conventional muds creates high frictional pressure losses during circulation in long sections, leading to unacceptably high ECDs in narrow drilling windows. High downhole temperatures can degrade the solids-carrying capacity of conventional muds, causing both dynamic and static barite sag and increasing the risk of loss of well control in high-angle wells. Oil-based muds can absorb large volumes of gas and this can cause well control problems too if the muds remain static for long periods in long horizontal holes. To make things worse, an influx of hydrocarbon gas into oilbased mud may destabilize the formulation and cause barite sag. Laboratory return permeability tests done on samples of a range of conventional mud types taken directly from the field show that they can cause considerable formation damage2, and the presence of very high levels of barite in high-weight muds formulated for high-pressure wells cannot improve matters. The use of Corrosion Resistant Alloys (CRA) in HPHT wells has been exposing fundamental flaws in the performance of conventional completion fluids based on chloride and bromide brines. It is well-documented that severe localized corrosion and stress corrosion cracking of CRA tubulars will take place in HPHT wells if they are exposed to chloride and bromide brines containing oxygen, CO2 or H2S 3-9. Furthermore, the sulfur-containing corrosion inhibitors commonly used in halide brines are known to decompose to H2S at high temperatures and create another source of stress corrosion cracking10. To date the vendors of halide brines seem to have made little progress towards finding an effective inhibitor to mitigate the serious corrosion problems created by their products in HPHT wells. In conclusion, a review of the challenge posed to conventional fluids by the demands of HPHT operations indicates that the use of hydrocarbons, solid weighting agents and halide brines (chloride and bromides) in drilling muds and completion fluids increases the risk of problems with well
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control, well integrity and well productivity. The negative influence of conventional fluids on drilling and completion operations can be sufficiently serious to compromise safety and degrade the economics of difficult or ambitious HPHT field developments. The birth of formate brines In the early-1990’s Shell had a small drilling fluids research team based in The Netherlands looking at how to deal with the problems caused by conventional fluids in HPHT operations. The team decided that the best way forward was to focus on finding a new fluid system that could provide all of the required functionality under HPHT conditions without resorting to the inclusion of hydrocarbons, solid weighting agents and halide brines. In their view the ideal solution was one that: • • • • • • • •
reduced hydraulic flow resistance eliminated solids sag did not solubilise hydrocarbon gases was not destabilized by the influx of reservoir gases reduced localized or pitting corrosion by acid gases eliminated stress corrosion cracking did not require the use of corrosion inhibitors avoided causing formation damage
It appeared that an aqueous formulation based on solidsfree, non-corrosive brine might provide the required properties. The question of which brine to use had already been partially answered by another of Shell’s research teams working on drilling fluid viscosfiers in the mid-1980s. This team had discovered that the temperature stability of common drilling fluid polymers was enhanced when they were dissolved in aqueous solutions containing high levels of sodium and/or potassium formates11. This insight gave them novel ability to formulate solids-free brine formulations with densities up to SG 1.57 (13.1 ppg) that had viscosity and fluid loss control stability at high temperatures. Further investigation showed that the density ceiling of formate brine systems could be extended to SG 2.30 (19.2 ppg) with caesium formate12-14. This breakthrough made it possible to create a seamless suite of formate brines suitable for use as solids-free drilling and completion fluids across the commonly required density range; a feat that had never been possible before. At the closing stages of the first phase of product development in 1995 the perceived advantages of the formate brines when compared with conventional HPHT drilling and completion fluids were 15: • Minimal formation damage • Maintenance of additive properties at high temperatures • Elimination of barite and its sagging problems • Reduced hydraulic flow resistance • Lower ECDs • Lower swab and surge pressures • Better power transmission to motors and bits • Low gas solvency • Better kick detection and well control • faster flow-checks
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• • • • • • • • •
Low potential for differential sticking Naturally lubricating Reduced torque and drag Inhibition of hydrate formation Non-hazardous Very low corrosion rates, local and general No stress corrosion cracking Compatibility with elastomers Biodegradable and posing little risk to the environment
The advent of fluids with such a unique set of performance advantages promised to eliminate a host of HPHT well construction problems caused by the inherent deficiencies of traditional drilling muds and brines. First field trials of formate brines in HT wells In 1996 Mobil conducted the first field trial of a formate-based drilling fluid in a high temperature well 16. Mobil reported that the use of potassium formate brine as a low-solids drill-in fluid provided the following benefits in this first trial: • Excellent polymer stability at 154°C (310°F) • Effective hole cleaning • ROP increased by 20% • No formation damage (skin factor=0) • Thin, easily removable filter cake • Good inhibition of formation clays • No corrosion • Reduced incidence of differential sticking • Low treatment costs during drilling Over the next 3 years Mobil used potassium formate brine as a drill-in fluid in a further 15 deep gas wells in Northern Germany. The performance of these fluids was reviewed in 2000 17. The potassium formate brine was used by Mobil in an attempt to eliminate the drilling problems that had occurred in offset wells where bottomhole static temperatures were as high as 155oC (311oF). The problems encountered with conventional water-based polymer mud included inadequate solids suspension, poor solids transport, stuck pipe, and tight holes. Mobil’s migration to formate-based fluids eliminated most of their problems and brought well construction costs under control. The drilling fluids were formulated using potassium formate brines with densities up to SG 1.55 (12.9 ppg). Xanthan polymer was added for viscosity control, and PAC or modified starch was used to provide fluid-loss control. Sized calcium carbonate particles (1-3%) were added for pore bridging. The wells were all drilled without any borehole or fluid-related problems. There were no sticking problems, no build-up of cuttings beds, and the torque and drag was immediately reduced after displacing to formate mud. The fluid costs and maintenance costs were significantly reduced as a result of using the potassium formate brine. Other benefits attributed to the brine included: • • •
25% lower pump pressures 25% increased ROP 100% success rate in running production liner
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Once the wells had reached TD, the used drilling fluid was processed through normal solids-control equipment to remove the majority of bridging agents and drill solids. The processed fluid was then used as a completion fluid during the completion phase. The wells were put on production with a typical production rate 35% higher than expected (or higher than previous offset wells). Mobil concluded 17: • Formate-based fluids have been applied as high density, temperature stable, low solids, environmentally friendly, non-damaging, non-corrosive drilling and reservoir drilling fluids • The use of formate-based fluids has resulted in a dramatic increase in drilling performance and hydraulics. • Since the use of formate-based fluids has been implemented the productivity of wells has increased compared to wells drilled with conventional muds • Stuck-pipe incidents have been significantly reduced with formate-based fluids due to thinner filter cakes and the naturally low friction coefficient of formates. • Despite exposure to temperatures of up to 165°C (329°F) BHST the polymers in the formate brine have retained their stability. • Corrosion has been minimal to negligible. A decade later potassium formate brines are continuing to provide the solution to the challenges posed by drilling deep high-angle gas wells. In SPE paper 92407 and accompanying slides18,19, Saudi Aramco have described how they have successfully used fluids based on potassium formate brine to drill and complete a series of long horizontal wells at 13,900 ft to 14,600ft TVD in hard and abrasive sandstone. Aramco report that one of the first wells drilled with a low-solids SG 1.44 (12.0 ppg) formate fluid exhibited “greatly improved drill string/wellbore lubricity and bit performance, reduced torque and drag, reduced ECD’s and lower pump pressures”. Wells Tinat-3 and Hawiyah-201 gave excellent flow test results, the best seen to date in their respective field. Cesium formate production By the end-1996 it was clear, from Mobil’s initial field trials of potassium formate, that low-solids fluids based on formate brines with densities up to SG 1.55 (12.9 ppg) could indeed fulfil their promise in deep gas well drilling and completion operations where the BHSTs extended up to 165oC (329°F). The only factor preventing the field testing of formates under even more extreme conditions was that there was insufficient cesium formate brine available to make useful volumes of high-density formate brines for HPHT drilling and completion. It was at this critical point that Cabot Corporation came to the rescue and announced that it was to build a large-scale caesium extraction plant, the only one of its kind in the world, at the TANCO mine site located in Manitoba, Canada. Without this timely intervention by Cabot the high-density formate brines would not now be available in kiloton quantities to fill the gap left by the failure of conventional drilling and completion fluids to perform adequately in HPHT well constructions. Mining started on the TANCO site in 1929 when Jack Nutt Mines Ltd opened a shaft to extract tin ore from the pegmatite
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rock body located under Bernic Lake. The pegmatite was found to contain around 80 different minerals within 8 mineralogical zones, and it was mined intermittently for lithium and tantalum for the next 60 years. One of the pegmatite zones is made up of high-quality pollucite ore (cesium silicate) and contains >80% of the world’s known reserves of caesium. Cabot Corporation purchased the mine in 1993 and within 3 years embarked on a $50 million investment program aimed at creating a mining and extraction facility capable of producing commercial quantities of cesium formate from the pollucite ore body under Bernic Lake. Within a further 2 years the production plant was producing 700 bbl/month of SG 2.2 (18.3 ppg) cesium formate brine only for use in HPHT drilling and completion fluids. To ensure that distribution channels were kept clear Cabot Corporation established its own specialist fluid service company, Cabot Specialty Fluids (CSF), that provides the cesium formate brines to oil companies on a day-by-day rental basis. CSF has brine storage and service centres on the Gulf coast in USA, and at locations in UK, Norway, Dubai and Egypt. At the time of writing the company has 30,000 bbl of SG 2.2 caesium formate brine in stock, or being used in the field. First cesium formate applications in HPHT wells Offshore UK Cesium formate brine first entered service as an HPHT completion fluid in September 1999. It was successfully applied as SG 1.80 (15 ppg) perforating fluid in a BHST 185oC (365oF) well in the Shearwater field operated by Shell UK. Just a month later Total UK used SG 1.90 (15.8 ppg) cesium formate brine as an HPHT completion fluid in the Dunbar field. This was followed by a further 7 applications of SG 2.19 (18.2 ppg) cesium formate brines as completion and workover fluids in Total’s Elgin/Franklin fields over the next 12 months. The BHST in one of these wells was as high as 207oC (405oF) and cesium formate brine was exposed to this temperature for 18 months during a well suspension operation. Over a period of 6 years cesium formate brine has been used 24 times by Total as an HPHT completion fluid in their Dunbar, Elgin, Franklin and Glenelg fields. Offshore Norway Only 16 months after first field trial as a completion fluid an SG 1.92 (16 ppg) cesium formate brine was used with great success as a drill-in and completion fluid in the first of Statoil’s Huldra wells (BHST: 147oC or 297oF) in the Norwegian sector of the North Sea. Five more Huldra wells were drilled and completed with cesium formate brines between March 2001 and April 2002. Statoil went on to drill-in, core, log and complete 2 highangle HPHT wells in the Kristin field (BHST: 175oC or 347oF) with a fluid based on SG 2.09 (17.40 ppg) caesium formate brine. In June 2004 Statoil began using SG 2.09 (17.40 ppg) cesium formate brine as a drill-in and completion fluid for a series of 7 HPHT wells in the Kvitebjoern field. Statoil have used cesium formate brines in 44 HPHT well operations in the past 5 years.
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Offshore USA In early-2002 BP used SG 2.11 (17.60 ppg) cesium formate brine for an HPHT well (BHST 176oC or 350 oF) intervention job in the offshore High Island field. Three years later Walter Oil and Gas used a 17.2 ppg cesium formate brine as a completion fluid at 215oC (420oF) in a Mobile Area 862 well. Onshore In November 2005 the Hungarian operator, MOL, used SG 1.86 (15.5 ppg) caesium formate brine as a completion fluid for a perforating and frac-pac operation in gas well Vetyem-1. This was the first use of caesium formate brine in an onshore HPHT well. Overview of cesium formate use in HPHT wells The formate brines make perfect drilling and completion fluids for difficult well construction projects where extraordinary fluid performance is critical for economic success. They have been used in more than 400 wells since their commercial introduction in 1993 and the demand for formate brines has been growing steadily at a compound rate of approximately 30% per year over the past decade. As an indication of the current dimensions of the business it is estimated that the annual revenues generated from the sale and rental of formate brines to the oil industry in 2005 should exceed $ 45 million. Since entering service in 1999 cesium formate brines have been used in 101 individual HPHT operations in 21 different fields. In this time they have passed extensive and rigorous field-testing: • At densities up to SG 2.25 ( 18.7 ppg) • At temperatures up to 215oC (420oF) • For periods up to 18 months downhole • In hole-angles from near-vertical through to horizontal • In oil, gas and condensate reservoirs (all sandstone) with permeabilities from < 1mD to 2 Darcy Figure 1 shows the applicational segmentation of cesium formate jobs to date (October 2005). The majority of applications have been completion jobs, 54 with straight cesium formate brine or blended potassium/cesium formate brines and 10 with low-solids oil-based fluids containing cesium formate brine as the soluble weighting agent 20-22. The completions have been of various kinds: • Cased and perforated • With sand control screens • Barefoot (openhole) • Gravel pack So far only some 20 of the 64 completion operations have been reported in SPE papers 1,20-24 but the track record of the cesium formate brines appears to have been flawless throughout. Perforating with cesium formate brine after drilling-in with oil-based muds has been a particular success story 22. Laboratory studies have shown that formate brines are non-corrosive, and protect carbon steels and CRA against localized/pitting corrosion caused by acid gases 8,25,26. Just as importantly, formate brines do not cause stress corrosion cracking of CRA tubulars at high temperatures, even in the presence of acid gases 27. Field use has validated the findings
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of these laboratory corrosion studies. Well productivities appear to have either met or exceeded expectations, as is normally the case when formate brines are used as drill-in or completion fluids 28,29. The risk of thermal decomposition of formates at high temperatures is a common concern to new users of caesium formate. In practice, however, none of the five major oil companies who regularly use cesium formate have been able to find any evidence of thermal decomposition taking place in their HPHT wells. The cases examined include the Elgin/Franklin well suspension operations where cesium formate brines have been exposed to downhole temperatures of 207oC (405oF) for periods of more than year 30. Cesium formate brines have been used 16 times as HPHT drill-in fluids for difficult high-angle wells, all so far in the North Sea and almost entirely (15) with Statoil (in the With the Huldra23, Kvitebjoern and Kristin fields24). exception of the two Kristin wells, where Statoil experienced problems with hole enlargement in some shale sections 24, the project managers have all expressed satisfaction with the field performance of caesium formate brines as the basis for lowsolids HPHT drill-in fluids. The following list of comments is taken from the five public domain papers 1,20-24 written by BP and Statoil engineers on their experiences of using drill-in and/or completion fluids based on cesium formate brines: General • Major operational success for BP • Cesium formate has a niche application in HPHT wells with open hole completions Well productivity • Return permeability tests show a substantial improvement • Good well flow performance • Resulted in six-fold increase in well production • Use of cesium formate is an important contribution to improving well productivity • Target production rates will be easily achieved • Clean-up treatments not necessary • Reduced negative effects from incompatibilities between drilling fluid and completion fluid • Reduced risk of screen plugging • High productivity from wells Fluid stability • Stable fluid properties at high temperatures • Stable mud properties Well control • No well control or loss situation • Provides an extremely good well control environment • No sag potential • Elimination of barite sag • Low gas solubility • Virtual elimination of gas diffusion into horizontal wells • Quick thermal stabilization during flow checks • Well stabilizes quickly during flow checks
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Hole stability and cleaning • Good hole stability in interbedded sand and shales • No hole stability problems • Caliper log of 8 ½” hole shows 9” in shale section above reservoir, and 11” in coal layers • Good hole cleaning • Less mud conditioning and wiper trips than usual Hydraulics • ECD is generally SG 0.04-0.06 at 4,500 metres • Good correlation between PWD data and hydraulic calculations • Reduced ECD improved ROP in hard formations • Lower ECDs (SG 0.03-0.05) than with OBMs • Good ROPs • Fast tripping speeds • Fast casing running speeds • ECD is higher when drilling clay than when drilling sand • Thorough understanding of fluid behavior • Drilled reservoir at 10 metres/hour • Low ROP in shale solved by using PDC bit with sharp cutters Differential sticking • Low potential for differential sticking • Successfully drilled long horizontal at only 200 psi overbalance Lubrication • Torque values indicate friction factors as low as 0.22 • Casing wear similar to that observed with OBMs • No need to add lubricants Materials compatibility • Aflas elastomers used on all plugs and packers • No tool failures or incidents relating to elastomers Cementing • Compatible with cement slurries • Very effective casing shoe squeeze on first attempt Completion • Transition from drill-in fluid to completion fluid was simple, since both systems use same base fluid • Less screen plugging risk Logging • Logging interpretation is manageable • Filtrate can be non-static during data acquisition • Consider acquisition of core data to calibrate log response • Problems getting WL-logs past coal layer • Results demonstrate that the effects of formate muds on nuclear logs can be accurately predicated 31 Effect on rig time • Drilling benefits have given rig time savings • Reduced time to complete the well
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In addition to normal use as HPHT drill-in and completion fluids the cesium formate brines also have applications as stand-by kill pills and stand-by stuck-pipe release pills. In these cases the brines are sent offshore, on long-term rental, for contingency reasons. The brines have one further important use, namely as solids-free well suspension fluids, where they have been supplied on rental terms for up to 18 months. These assorted applications have so far accounted for 21 field requests for cesium formate brines. Figure 2 shows the user segmentation of cesium formate jobs to date. Statoil has been the biggest user by far, followed by Total/Elf, Norsk Hydro, Shell and BP. On a regional basis all but 3 of the 100 offshore operations using cesium formate have been in the North Sea. Published field case histories Huldra field, offshore Norway, 200123 Huldra is a gas condensate field in the Norwegian sector of North Sea operated by Statoil. During drilling and completion of this field, high temperature and pressure conditions were encountered in the reservoir section (675 bar, 150ºC or 302oF). The difference between the pore pressure and fracture pressure gradient was small in the reservoir. The Huldra gas stream contained 3-4% CO2 and 9-14 ppm H2S. The wells were drilled at a 45º - 55º inclination through the reservoir and completed with 300-micron single-wire-wrapped screens. When the first production well was drilled in this field, with oil-based mud, a severe well kick was experienced while running the sand screens. The main reason for the kick was a loss of drilling-fluid density due to barite sag during the wiper trip. A cesium formate-based drill-in fluid was therefore selected for the following wells to improve well control. The main benefits identified with the cesium formate brine compared with the oil-based fluid were: no sag potential, low ECD, less screen plugging risk, (low solids), use of solids that could be acidized (CaCO3), low gas solubility, environmentally friendly, and quick thermal stabilization during flow checks. Return permeability testing was carried out and the predicted reduction in formation permeability after drawdown (due to adherence of residual filter cake) was in the range 3670%. Further testing showed that incorporating a treatment with dilute organic acid to remove residual filter cake was effective in restoring core permeability to its near-native state. The operator decided to go ahead and use formate fluid, knowing that any formation damage would be shallow and could be removed by a simple dilute acid soak at balance. The drilling operation itself was characterized by good hole stability, low ECD and good hole cleaning. The excellent rheology and thermal stability of the drilling fluid led to rigtime savings from faster tripping speeds, faster casing-running speeds, less mud conditioning and fewer wiper trips. The ROP was also good, at 10 metres/hour. The drilling fluid was circulated over a combination of 250, 300, and 400-mesh shaker screens before the completion screens were run. After running the screens, the drilling fluid was replaced with filtered cesium formate completion brine. Statoil report that the six Huldra wells drilled and completed with cesium formate brine are each producing with excellent average Productivity Indices of around 1.9 million
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scf/day/psi. In fact plateau production rates were achieved from the first three wells of the six-well project. The Huldra project manager is quoted as saying: “For the specific conditions of the Huldra field there was no realistic fluid alternative for successfully drilling and completing the wells”. There were no obvious signs of formation damage in the wells, and no acid stimulation was required. This finding casts some doubt over the the meaning of results obtained from the reservoir-conditions core-flood testing at an independent laboratory which had suggested that the wells would be impaired by inadequate removal of drilling fluid filter-cake under drawdown. Devenick field, offshore UK, 20011 Devenick is a gas condensate field operated by BP in the UK sector of the North Sea. A SG 1.68 (14 ppg) cesium formate fluid was chosen by the operator to drill and core a 1,000 metre horizontal HPHT appraisal / development well in the field. The low-permeability sandstone matrix of the Devenick reservoir is very hard and abrasive, and is deemed to be a significant challenge to drill and complete. A long horizontal wellbore was required in order to yield sufficient productivity and to penetrate the different reservoir segments. The priority was to minimize reservoir damage by using a low-solids drilling fluid. With a planned maximum deviation of 88o, and a BHST of 135oC (275oF), barite sag and well control issues were a concern. Formate brine was believed to offer several advantages over oil-based mud (OBM), and was primarily selected on grounds of formation damage characteristics, low ECD and potential for improving ROP and well control. Return permeability testing on Devenick reservoir core samples indicated that the cesium formate brine would cause minimal formation damage compared to oil-based mud. This was an important consideration given that an openhole completion was programmed. Also, hydraulic modeling suggested that the formate brine would reduce the ECD by approximately 300 psi over an OBM, giving wider safety margins between pore and fracture pressure. Equally important for this well was the fact that the ECD reduction would reduce the apparent rock strength seen by the bit by 23%, arguably yielding a similar improvement in ROP. Other horizontal HPHT wells drilled previously by BP had suffered well-control problems, and the use of formate brine was believed to offer a much-reduced well-control risk over an OBM fluid. Elimination of barite sag and no diffusion of methane into the horizontal wellbore were the main reasons for this. With the hard nature of the reservoir sands, slow drilling rates of 2-3 m/hr and short bit life were expected. The 6” interval was programmed for 60 days and 17 round trips for alternate drilling and coring runs. A turbine-motor was used instead of a mud-motor. Significant rig time was saved during drilling since the fluid was stable and did not require additional time to circulate and condition mud to counter sag during trips. Coring was difficult because the angle of the bedding plane kept causing the core samples to break. After a successful logging run the hole was displaced to clean cesium formate brine for the completion.
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The reported results from the completed well were promising, with good production and zero skin. The BP project team is quoted as saying that they felt the well would have been difficult to deliver without the use of cesium formate brine. In addition to the advantages discussed above, the team felt that the fluid brought a number of HSE advantages such as elimination of the need for skip & ship, no well-control incidents and better integration between drilling and completion. The advantages with the fluid far outweighed the disadvantages, which were fluid cost and increased complexity in the reservoir log analysis. Visund field, offshore Norway, 200222 The Visund field is a subsea development offshore Norway. Norsk Hydro put the field on production in 1999. The field was taken over by Statoil in 2003. Visund has proven to be a highly complicated reservoir with a complex geology. Permeabilities range from 300 to 3,000 mD. The Visund reservoir was accessed by a series of wells drilled and completed with long horizontal sections to reach several targets with one well. The wells have relatively high pressures and moderate temperatures (440 bar, 115ºC or 239oF). Sand control was aided by oriented perforating in the direction of maximum stress. The wells were drilled at high overbalance with oil-based mud. The long drilling times under these conditions resulted in deep mud filtrate invasion around the wellbore. The first wells were perforated with standard oriented perforating system with zinc-cased charges in a SG 1.65 (13.8 ppg) CaCl2/CaBr2 perforating kill fluid. When the wells were put on stream, the chokes were plugged by large chunks of zinc oxide. These wells showed significantly lower productivities than should be expected from the reservoir characteristics. A study was carried out to identify the source of the problem. Several areas of improvement were identified, including the fluid system. The CaCl2/CaBr2 brine formulation proved to be unstable and viscous, making it difficult to achieve a good cleanup. The brine was also found to be incompatible with the formation water. Further laboratory studies showed that reactions between zinc powder by-products from the charges and CaCl2/CaBr2 brine caused the kill pill to lose its fluid-losscontrol properties, which then resulted in formation damage. The idea of replacing the brine with oil-based mud was abandoned because of high particle content. A new perforating system was developed which, among other changes, replaced the zinc charges. The CaCl2/CaBr2 perforation fluid was replaced with a low-solids oil-based fluid weighted up with cesium formate brine. Five new oilproducing wells were drilled and perforated with the new system under dynamic underbalanced conditions. Productivity Indices for the previous wells were in the range of 60-90 Sm3 oil /day/bar, whilst the new wells were ranging from 300 to 900 Sm3 oil /day/bar. It was concluded that the effect of the changes to the perforating system, combined with the application of dynamic underbalance and the new formateweighted fluid, was responsible for the 3 - to 6-fold increase in productivity. The formate-based fluid is believed to be one of the main contributors to the improved well productivity.
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Kristin field, offshore Norway, 2003 24 Kristin is a HPHT gas condensate field in the Norwegian sector of North Sea operated by Statoil. The Kristin Field is located approximately 240 km west of the mid-Norwegian coast with an average water depth of 360m. With a reservoir pressure and temperature of around 900 bar and 170°C (338oF) respectively, Kristin has been labeled a high pressure, high temperature (HPHT) field. The Kristin field development is based on four sub-sea templates with a total of twelve production wells. All the wells are completed with 6-5/8” open-hole screens with a slot width of 350-micron. The reservoir has a pore pressure equivalent to a mud weight of SG 1.98. The difference between the pore pressure and fracture pressure gradient in the reservoir is small, giving a narrow drilling window. The reservoir sections (300-400 metres, 32º-46º inclination) of the first two Kristin wells were drilled and cored at a 50 bar overbalance using a fluid based on SG 2.09 (17.40 ppg) cesium formate brine. Statoil report that the ECD was in the range SG 0.04-0.06, comparing favorably against oil-based muds that generally give ECD of SG 0.09-0.11. The coring runs were successful but the logging was difficult apparently because of hole enlargement (16½” and occasionally larger) in the Lange shales above the reservoir. It is understood that similar hole enlargements were seen in exploratory wells drilled using oil-based mud. The Kristin wells were plugged back for temporary suspension since completion equipment was not ready. They have since been completed in cesium formate brine. Kvitebjorn field, offshore Norway, 2004/5 24 The Kvitebjorn field is another HPHT (BHST: 145oC or 293oF) gas condensate field in the Norwegian sector of the North Sea. Over the past 18 months the operator has drilled and completed the 300-400 metre reservoir sections (24-30o deviation) of six Kvitebjorn wells with fluids based on SG 2.02 cesium formate brine. Statoil report that the ECD during drilling was low, as previously seen in the Huldra and Kristin wells. The first Kvitebjorn well, A-04, was cored to TD in the cesium formate brine and then logged successfully on wireline. Unlike the Kristin wells, the hole sizes and hole condition through the shales in the Kvitebjorn wells are said to have been good. The 300-micron sand screens were run without incident before displacing from caesium formate drillin fluid to cesium formate completion brine. The 7” production string was also run without incident. The brine losses for the drilling phase were 28.5m3 (179 bbl), which compares favorably with the 35m3 (220 bbl) programmed estimate. There were 8 round trips for coring, etc., with the 7.56m3 (47 bbl) total tripping loss giving an average 0.95m3 (6 bbl) loss per trip. On the second Kvitebjorn well, A-05, the formate brine losses for the drilling phase were 30.7m3 (193 bbl), which compares favorably with the 36m3 (226 bbl) programmed estimate. There were 7 round trips, with the 3.02m3 (19 bbl) total tripping loss giving an average 0.43m3 (2.70 bbl) loss per trip.
8
IADC/SPE 99068
Conclusions The many papers written by operators, over a period of 10 years, on their experiences of using formate brines have indicated that these fluids can add significant value to difficult well construction projects by: - Improving well control - Reducing NPT - Improving well productivity - Improving well integrity and lifetime - Enabling complex well constructions - Facilitating access to difficult reserves - Reducing waste disposal costs - Reducing waste liability
development of cesium formate brine as a HPHT drilling and completion fluid. The authors would also like to offer their sincere thanks and congratulations to everyone who has been involved in the development, production, approval and field testing of cesium formate brine.
The development of cesium formate brine began 15 years ago as Shell’s response to demands for a solution to the performance shortcomings of conventional drilling and completion fluids that were being exposed by the demands of HPHT well construction operations. The view of the original development team back in the early-1990’s was that HPHT well control, integrity and productivity could be improved by the use of a novel drilling and completion fluid, such as cesium formate brine, that was a free of solid weighting agents, halides and hydrocarbons 12-15. It was fortunate that the management of Cabot Corporation embraced this view at an early stage and was willing to invest very large sums of money in making sufficient cesium formate brine and fluid engineering resources readily available to the oil industry. After 100 field applications of cesium formate brine in HPHT wells it seems that its original promise as a drill-in and completion fluid has been largely fulfilled. By using this lowsolids non-halide brine, operators have been able to drill and complete challenging HPHT wells with a degree of success, economy and security that would have been difficult to achieve using conventional fluids. Published field test results indicate that cesium formate brines have been meeting expectations in terms of providing the hydraulics, well control, well integrity and well productivity required to safely and economically deliver a high-quality HPHT well. Cesium formate has proven to be an excellent replacement for the high –density halide brines, and has just about completely displaced zinc bromide brine as a completion fluid in the North Sea arena. Formates have a good reputation as shale drilling fluids 32-36, and cesium formate brine itself has clearly provided good shale stabilization in 14 out of the 16 HPHT wells where it has been used as a drill-in fluid. The hole enlargement through cap-rock shale sections that have been reported in the two Kristin wells are therefore anomalous and need further investigation With the recent movement towards Maximum Reservoir Contact well geometries, and the discovery of further examples of incompatibilities between halide brines and CRA, it now seems that the schedule for the development and commercial production of cesium formate brine has been both timely and fortuitous.
References
Acknowledgments This paper is dedicated to Tony Clarke-Sturman and Philip Sturla, whose original invention in 1986 sparked the
Nomenclature CRA = ECD = HPHT = OBM = ROP = SG =
1.
Corrosion Resistant Alloy Equivalent Circulating Density High Pressure, High Temperature Oil-Based Mud Drilling Rate of Penetration Specific Gravity
Rommetveit, R., Fjelde, K.K., Aas, B., Day, N.M., Low, E. and Schwartz, H.: “HPHT Well Control; An Integrated Approach,” OTC 15322, Offshore Technology Conference, Houston, May 5-8, 2003. 2. Francis, P. A., Eigner, M.R.P., Patey, I.T.M. and Spark, I.S.C.: “Visualisation of Drilling-Induced Formation Damage Mechanisms using Reservoir Conditions Core Flood Testing”, SPE 30088, SPE European Formation Damage Conference, The Hague, The Netherlands, 15-16 May 1995. 3. Sutanto, H. and Semerad, C.A.W.: “Annulus Corrosion in High Temperature Gas Wells”, SPE Production Engineering, Vol. 5, pp 295-298, August 1990. 4. Ibrahim, M.Z., Hudson, M., Selamat, K., Chen, P.S., Nakamura, K. and Ueda, M.: “Corrosion Behaviour of S13Cr Martensitic Stainless Steel in Completion Fluid”, Corrosion/2003, Paper No. 03097, NACE International 2003, Houston, Texas, USA. 5. Silverman, S.A., Bhavsar, R., Edwards, C., Virally, S., and Foxenberg, W.: “Use of High Strength Alloys and Elastomers in Heavy Completion Brines”, SPE 84515, SPE Annual Technical Conference, Denver, Colorado, October 5-8, 2003. 6. Stevens, R., Ke, M., Javora, P.H. and Qu, Q.: “Oilfield Environment-Induced Stress Corrosion Cracking of Corrosion Resistant Alloys in Completion Brine”, SPE 90188, SPE Annual Technical Conference, Houston, Texas, USA, September 26-29, 2004. 7. Craig, B.D. and Webre, C.M.: “Stress Corrosion Cracking of Corrosion Resistant Alloys in Brine Packer Fluids”, SPE 93785, presented at 2005 SPE Production and Operations Symposium, Oklahoma City, OK, USA, April 17-19 2005. 8. Leth-Olsen, H.: “CO2 Corrosion in Bromide and Formate Well Completion Brines”, SPE 95072, SPE 2nd International Symposium on Oilfield Corrosion, Aberdeen, UK, 13th May 2005. 9. Scoppio, L., Nice, P.I., Nødlans, S., LoPiccolo, E.: “Corrosion and Environmental Cracking Testing of a High-Density Brine for HPHT Field Application.” Corrosion 2004 NACE , Paper No. 04113, New Orleans, USA, March 28 – April 1, (2004) 10. Mack, R., Williams C., Lester, S. and Casassa, J.: “ Stress Corrosion Cracking of Cold Worked 22Cr Duplex Stainless Steel Production Tubing in High Density Clear Brine CaCl2 Packer Fluids”, Corrosion/2002, Paper No. 02067, NACE International 2002, Houston, Texas. 11. Clarke-Sturman, A.J. and Sturla,P.L.: “Aqueous Polysaccharide Compositions,” European patent 259 939 (16 March 1988). 12. Downs, J.D.: “Formate Brines: New Solutions to Deep SlimHole Drilling Fluid Design Problems,” SPE 24973, European Petroleum Conference, Cannes, 16-18 November 1992. 13. Downs, J.D.: “Formate Brines: Novel Drilling and Completion Fluids for Demanding Environments,” SPE 25177, 1993 SPE
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International Symposium on Oilfield Chemistry, New Orleans, 2-5 March 1993. 14. Downs, J.D., Killie, S.K. and Whale, G.F.: “Development of Environmentally Benign Formate-Based Drilling and Completion Fluids,” SPE 27143, SPE 2nd International Conference on Health, Safety and Environment in Oil & Gas Exploration and Production, Jakarta, 25-27 January 1994. 15. Howard, S.K.: "Formate Brines for Drilling and Completion: State of the Art," SPE 3049 presented at the 1995 SPE Annual Technical Conference, Dallas, 22-25 October 1995. 16. Sundermann, R. and Bungert, D.: “Potassium-Formate-Based Fluid Solves High Temperature Drill-In Problem,” Journal of Petroleum Technology (November 1996) 1042. 17. Bungert, D., Maikranz, S., Sundermann, R., Downs, J., Benton, W. and Dick, M.A.: “The Evolution and Application of Formate Brines in High-Temperature/High-Pressure Operations,” IADC/SPE 59191, IADC/SPE Drilling Conference, New Orleans, 23-25 February 2000. 18. Simpson, M.A., Alreeda, S.H., Al-Khamees, S.A., Zhou, S., Treece, M.D. and Ansari, A.A.: “Overbalanced Pre-Khuff Drilling of Horizontal Reservoir Sections with Potassium Formate Brines”, SPE 92407, 14th SPE Middle East Oil & Gas Show and Conference, Bahrain, 12-15th March 2005. 19. Alreeda, S.H.: “Overbalanced Pre-Khuff Drilling of Horizontal Reservoir Sections with Potassium Formate Brines”, presentation slides for SPE 92407, presented at 14th SPE Middle East Oil & Gas Show and Conference, Bahrain, 12-15th March 2005. 20. Jiang, P., Taugbol, K., Mathisen, A.M., Alteras, E. and Mo., C.: “New Low-Solids Oil Based Mud Demonstrates Improved Returns as Perforating Kill Pill”, SPE 73709, presented at SPE International Synmposium on Formation Damage, Lafayette, LA, Feb 20-21 2002. 21. Taugbol, K., Lilledal, L., Juel, H., Svanes, K. and Jakobsen, T.M.: “The Completion of Subsea Production Wells Eased by the Use of Unique, High-Density, Solids-Free, Oil Based Completion Fluid”, IADC/SPE 87126, SPE/IADC Drilling Conference, Dallas, Texas, 2-4 March 2004. 22. Stenhaug, M., Erichsen, L., and Doornboch, F.H.C.: “A Step in Perforating Technology Improves Productivity Of Horizontal Wells In the North Sea,” SPE 84910, SPE International Improved Oil Recovery Conference, Kuala Lumpur, 20-21 October 2003. 23. Saasen, A., Jordal, O.H., Burkhead, D., Berg, P.C., Løklingholm, G., Pedersen, E.S., Turner, J. and Harris, M.J.: “Drilling HT/HP Wells Using a Cesium Formate Based Drilling Fluid,” IADC/SPE 74541, IADC/SPE Drilling Conference, Dallas, 2628 February 2002. 24. Aase, M.: “ What to Take Into Account When Planning Your HPHT Project”, presentation by Statoil to HPHT Well Drilling, Completing and Monitoring Conference arranged by IQPC, Aberdeen, UK, 6-7 December 2005. 25. Leth-Olsen, H.: “CO2 Corrosion of Steel in Formate Brines for Well Applications.” Corrosion 2004 NACE, Paper No. 04357, New Orleans, USA, March 28 – April 1 (2004). 26. Downs, J.D., Benton, W., Carnegie, A. and Leth-Olsen, H.: “Inhibition of CO2 Corrosion by Formate Fluids in High Temperature Environments”, Proceedings of the RSC Chemistry in the Oil Industry IX Symposium, Manchester, UK, 31 Oct-2 Nov 2005. 27. Downs, J.D. and Leth-Olsen, H.: “Effect of Environmental Contamination on Susceptibility of Corrosion Resistant Alloys to Stress Corrosion Cracking in High-Density Completion Brines”, SPE 100438, SPE 2006 Oilfield Corrosion Symposium, Aberdeen, UK, 30 May 2006.
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28. Byrne, M., Patey, I., George, E., Downs, J.D. and Turner, M.: “Formate Brines: A Comprehensive Evaluation of Their Formation Damage Control Properties Under Realistic Reservoir Conditions,” SPE 73766, SPE International Symposium on Formation Damage Control, Lafayette, 20-21 February 2002. 29. Downs, J.D., Howard, S.K. and Carnegie, A.: “Improving Hydrocarbon Production Rates Through the Use of Formate Fluids”, SPE 97694, presented at SPE International Improved Oil Recovery Conference in Asia Pacific, Kuala Lumpur, Malaysia, 5-6 December 2005. 30. Benton, W., Harris, M., Magri, N., Downs, J.D. and Braaten, J.: “Chemistry of Formate Based Fluids”, SPE 80212, presented at SPE International Symposium on Oilfield Chemistry, Houston, Texas, 5-8 February 2003. 31. Guo, P., Gilchrist, W.A., page., G, Wills, P. and Brown, A.M. : “Interpretation of Nuclear Logs in Formate-Based Drilling Fluids in a North Sea Well” , presented at SPWLA 43rd Annual Logging Symposium, June 2-5, 2002 32. Chenevert, M.E.: “Drilling Fluid Optimization in Shales. Swelling Pressure and Compressive Strength of Shale, Topical Report,” Prepared for Gas Research Institute, Contract No. 5093-210-2898, December 1998. 33. Hallman, J.H., Mackey, R., and Swartz, K.: “Enhanced Shale Stabilization With Very Low Concentration Potassium Formate/Polymer Additives,” SPE 73731, SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, 20-21 February 2002. 34. Mackey, R. and Hallman, J.: “Low Concentration Formate Fluids Improve Drilling in Water-Based Muds in Difficult Shale Environments in Western Canada,” IV SEFLU (Seminarion de Fluidos de Perforacion y Terminacion de Pozos), Isla de Margarita, Venezuela, 5-8 June 2001. 35. Hallman, J. and Bellinger, C.: “Potassium Formate Improves Shale Stability and Productivity in Underbalanced Drilling Operations,” CADE/CAODC Drilling Conference, Calgary, 2022 October 2003. 36. Zuvo, M., Bjornbom, E., Ellingsen, B., Buffagni, M., Kelley, A. and Trannum, H.C.: “High Resolution Environmental Survey around an Exploration Well Drilled with Formate Brine in the Barents Sea, Norway”, SPE 94477, 2005 SPE/EPA/DOE Exploration and Production Environmental Conference, Galveston, Texas, USA, 7-9 March 2005.
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3
2
6
16 Drilling
10
Comp/WO- brine Comp/WO- LSOBM Stand-by KF
10
Suspension Well test Stuck pipe pill 54
Figure 1 – Segmentation of caesium formate brine use by application, 1999-2005
6
2 1 11 1 Statoil Total
8
Hydro 44
Shell BP
13
Walter COP Dong Marathon MOL 24
Figure 2 – Segmentation of caesium formate brine use by operator, 1999-2005
