Formate Matters: Issue Ten
Your resource for the latest cesium formate news and industry insights.
Browse through the articles below or download the complete issue.
- New study: save weeks drilling and completing with formate fluids +More
- Join our workshops +More
- New formate technical manual updates +More
- The versatility of cesium formate +More
- Life of brine +More
- Full-scale testing reveals ROP-enhancing properties of formate brines +More
A new benchmarking study of 89 North Sea wells proves rig-time savings of up to 26 days when the optimum combination of well construction strategy and fluid type is chosen. Cesium and potassium formate fluids perform better than oil-based muds (OBMs) in both open-hole (OH) and cased and perforated (C&P) well constructions.
According to Ridge’s study, formate fluids deliver significant increases in ROP – 74% higher for HPHT platform wells, 38% higher for HPHT subsea wells and 68% higher for non-HPHT subsea wells.
We engaged Ridge AS (Ridge) to undertake an independent benchmarking study of how different well construction fluids in combination with common drilling and completion strategies affect rig time. The study of 56 HPHT wells and 33 non-HPHT wells provides a database for helping predict construction times for comparative well developments. Ridge, formerly Subsurface AS, is an independent consulting company headquartered in Norway with one of the largest HPHT well engineering teams in the country. Ridge provides well and completion support for many ongoing field developments in the North Sea and is Achilles JQS registered.
Fastest vs. slowest
Open-hole standalone sand screen (OH SAS) completions are faster than C&P completions, but fluid choice plays a crucial role in optimizing operations and saving further time and costs. In fact, switching from C&P completions using OBMs to OH SAS with formate fluids saves over three and a half weeks of rig time. Formate fluids also significantly speed up both well completion techniques. Ridge calculates:
- 17 days of rig-time savings in C&P wells – compare scenarios 3 and 5 in figure
- 13 days of rig-time savings in wells completed in simple OH SAS – compare scenarios 1 and 2 in figure
Ridge compares drilling time for operations completed with OBMs versus those using formate fluids and concludes: “It is evident that wells drilled with cesium/potassium formate are significantly faster than wells drilled with OBM.” The report then asks ‘why?’
Ridge provides several reasons for formate fluids’ improved performance based on a comprehensive literature review and findings from the benchmarking study:
- Longer bit runs and improved rate of penetration (ROP). Average ROP with formate fluids is 74% higher for HPHT platform wells, 38% higher for HPHT subsea wells and 68% higher for non-HPHT subsea wells.
- Formate fluids provide lower equivalent circulating densities (ECDs), eliminate risk of barite sag, improve borehole stability, provide better kick detection and minimize time to circulate out gas.
- Fewer wiper trips due to stable mud properties and elimination of sag.
- Less mud conditioning with formate fluids compared to OBMs.
- Faster and fewer flow checks.
- Improved hole cleaning in horizontal wells – lower ECDs permit higher pump rates and more turbulent flow.
- Pumps ramp up much quicker after connections without ECD-spike risk, due to fragile gels in formate fluids.
- Faster tripping through lower ECDs and larger swab/surge margins.
- Reduced tool failures through better cooling in formate fluids.
Ridge then studied completion type and fluid choice. Jan Tore Hatland, co-author of the Ridge report, says: “For completion operations, time savings are generally much less intuitive and are, to a much larger extent, related to how various fluids enable more time-efficient completion solutions, rather than direct time savings from the fluids. The study shows that lowsolids formate fluids are enablers for the fastest types of completions.”
Ridge observed that OH lower completions are typically delivered significantly faster than C&P completions. Low-solids, formate screen-running fluids enable OH completions and are compatible with clear formate brine in overbalanced upper completions. Further, the report shows that C&P completions with drill-pipe-conveyed perforation in overbalanced fluid are delivered significantly faster than C&P completions with wireline (WL) or coiled tubing (CT) underbalanced postcompletion perforations. This is most likely due to the long rig-up time for CT/ WL operations, combined with the limit of perforation guns per run. Low-solids or solids-free formate perforation fluid combined with clear formate brine in upper-completions enable overbalanced tubing-conveyed perforations. Importantly, Ridge notes that clean-up torig is usually not required when low-solids cesium formate fluids replace solidsladen OBMs for lower completions.
In addition to time and cost savings, Ridge finds formate fluids decrease risk by facilitating solids-free overbalanced operations. It states: “The level of well control preparedness required to handle a deep barrier leak during an underbalanced completion lies far beyond the normal competency levels that rig crews are certified for by the International Well Control Forum (IWCF). Any subsequent off-bottom kill operation will also be extremely complex and risky. Snubbing or drilling of a relief well may ultimately be required. When it comes to time savings, the main time-saving element is the elimination of the inflow test and the reduced risk of debris on top of the reservoir barrier. Cesium/potassium formate completion fluids allow solidsfree overbalanced operations and reduce risk in line with the ALARP (as low as reasonably practicable) principle.”
In its conclusions, Ridge finds significant value in drilling and completing HPHT and non-HPHT reservoirs with formate fluids stating: “The major time-saving potential is in their potential to enhance the probability of successfully delivering these wells in much shorter time and with lower risk.” Download key findings.
Figure: Predicted time to drill and complete an 8.5" HPHT reservoir section with five different configurations/fluids. Times are taken from the benchmarking study results as follows: a) platform well, b) section length (500 m), c) average net ROP (47 m/day for formate fluids and 27 m/day for OBM), d) average completion time (depending on completion type), e) average drill pipe perforation time (three days), f) average WL perforation time (ten days), g) clean-up to rig for OBM (two days).
Where formate fluid is used for drilling-in, lower completions and upper completions, it acts as the primary barrier through all operations.
What are formate fluids? What are their benefits? Should I consider using them in my next well? What does the latest research show? There are always questions, which is why we hold seminars and workshops to educate and answer the queries that arise. The next workshops are being held in Stavanger and Aberdeen on April 15 and 18 respectively. To reserve your place, please send us an email. We also run bespoke events, so if you’d like to instigate a seminar or workshop for your company tailored to your specific needs, please get in touch. There are no costs attached to arranging or attending these events.
The latest workshops were all run in Asia; Kuala Lumpur, Ho Chi Minh City and, most recently, Nusa Dua in Indonesia. All three focused on best well construction practice with emphasis on HPHT drilling and completion. Subjects included fluid choice, intervention and completion design, well integrity, wellbore stability, performance drilling and formation damage. The keynote speaker at all events was Professor Eric van Oort, Consultant and Chairman of Genesis RTS and Lancaster Professor in Petroleum Engineering at the University of Austin, Texas who presented his current research on wellbore stability and drilling performance that highlighted significant ROP increases in shales with formate fluids. All three workshops enjoyed good industry participation with drilling and completion engineers from oil and gas and service companies such as Petronas, Premier Oil, KPOC, Bien Dong, Cuu Long, Chevron, Saudi Aramco, Scomi and M-I Swaco attending.
Allan Grossart, segment manager oil and gas, says: “We really value the support shown from visitors during the workshops. They were a great success with constructive and lively debate, and lots of opportunities to network."
Professor Eric van Oort presenting his latest research. Why not book your own complimentary formate fluids workshop or seminar?
Our comprehensive formate technical manual is a live document continually updated with the latest research and knowledge on formate brines. In the last months, A2 Brine density and PVT data, A7 Thermophysical properties and B14 Solubility in non-aqueous solvents have all been renewed, the latter with substantial new material. View all of our formate technical manual chapters.
Cesium formate has been described as the ‘Swiss army knife’ of brines due to its wide range of uses. Drilling, completion, intervention and workover applications are well established, but lesser known is its effectiveness as a pill for breaking OBM filter cake, releasing stuck pipe and dissolving hydrates. Cesium formate brine’s versatility is due to its unique properties, particularly its natural high density and low water activity. With no added solids it is available and fully stable up to 2.3 g/cm3/19.2 lb/gal. As no additives or mixing are needed, cesium formate is brought into play quickly and rig inventory and deck space used for additive storage is greatly reduced.
A typical application where speed is of the essence is differentially stuck pipe. Cesium formate brine works fast downhole disrupting and effectively breaking OBM filter cake. Additionally, the brine dissolves hydrate plugs. The heavy cesium formate pill is easily spotted on top of a hydrate plug and gravity helps the brine to attack and dissolve the hydrate plug very efficiently. Cesium formate brine’s monovalent nature and mildly alkaline pH also mean it’s safe to handle. These qualities give it good environmental credentials with a gold rating from the United Kingdom’s Centre for Environment, Fisheries and Aquaculture Science, and similar approvals from other environmental organizations worldwide. It all adds up to a highly versatile brine for specific applications or stand-by purposes for those unforeseen events that need a fast response.
Cesium formate brine quickly disrupts and breaks filter cake to release differentially stuck pipe
John Downs, aka ‘the father of formates’, stepped into retirement last year knowing that he has initiated a revolution in well construction fluids. John’s interest in brines dates back more than 40 years. After graduating from Bath University, United Kingdom with a degree in biology in 1973 he joined Shell Research as a fermentation technologist growing bacteria to create products such as xanthan gum. To gain greater control over the fermentation process, John started growing bacteria on clear brines containing all of the bacterial nutrients in soluble form. Production rates increased and John filed his first xanthan patent.
Bring on the brines
John joined Shell Chemicals in the 1980s, selling xanthan to the oil industry as a drilling fluid viscosifier. In the meantime, his colleagues in Shell Research discovered great synergy between xanthan and a novel class of clear brines based on sodium formate and potassium formate. These formate brines viscosified with xanthan made excellent solids-free drilling and completion fluids. John took this exciting new technology with him in 1990 when he moved to Shell’s E&P laboratory in the Netherlands as a senior scientist tasked with developing better drilling and completion fluids. John explains: “Back in the 90’s, well drilling fluids were barite-laden slurries from a bygone era that slowed down drilling and complicated the well construction process. Replacing these old-fashioned slurries with clear formate brines made a lot of sense. They made the entire well drilling and completion process simpler, safer, faster and ultimately cheaper."
Denser does it
John’s immediate challenge was to find some way of increasing formate brines’ density. As potassium formate brine only went up to 1.57 g/cm3/13.1 lb/gal and not beyond, John turned to cesium formate produced by TANCO from its pollucite mine in Manitoba, Canada. His lab tests on cesium formate brine in 1990 showed that densities up to 2.30 g/cm3/19.2lb/gal were possible with this exciting product. This discovery opened up the possibility of drilling and completing wells entirely with solids-free formate brines.
John left Shell in 1995 to promote formate brines in the oil industry, eventually joining Cabot in 2004. Here, he worked in technical sales, marketing and product development concentrating on cesium formate, until setting up his own formate brine consultancy in 2012. John has published 30 papers on formate brines and is a recipient of the Cabot Lifetime Technology Achievement Award. We wish him a happy and healthy retirement.
John Downs presenting formate brines in 2008
A new full-scale drilling test performed in a high-pressure drilling simulator illustrates effects of water activity and solids content of formate brines on rate of penetration (ROP). It clearly shows significantly improved rates in shales. Key results are:
- 50% improvement for low-solids (10 ppb) mud and 20% improvement for high-solids (40 ppb) mud for high-salinity, 1.88 g/cm3/ 15.7 lb/gal formate mud compared to 1.92 g/cm3/16 lb/gal water-based mud (WBM)
- 60% improvement for low-solids (10 ppb) mud and 15% improvement for high-solids (40 ppb) mud for lower salinity, 1.34 g/cm3/ 11.2 lb/gal formate mud compared to 1.14 g/cm3/9.5 lb/gal WBM
Professor van Oort of the University of Austin, Texas completed the study using high-salinity cesium/potassium formate drilling fluid with low water activity and lower salinity cesium/potassium formate drilling fluid with higher water activity. These fluids were based on the same cesium/potassium formate blend, but one was significantly cut back with water. Both were viscosified with xanthan and, to study the effects of solids, 10 ppb calcium carbonate was added in the first test and 40 ppb in the second. Two WBMs with different densities were included as reference fluids. The tests were completed in Mancos shale at Baker Hughes’ high-pressured drilling simulator in Houston. Bottomhole pressure was 6,000 psi.
The research clearly shows that high-salinity formate mud increases shale-drilling speeds. Professor van Oort explains: “Faster drilling is facilitated through chemical osmosis, which dehydrates and strengthens clay-rich rocks. In turn, this forms a lubricating layer that helps prevent rock build-up on the cutter edges and cutter body, meaning failed rock is more efficiently cut and transported away from the bit.”
The study helps quantify field experience from several operators, including DMK Drilling Fluids in Canada, which saved days drilling each of 100-plus wells by replacing OBM with potassium formate brine. Read more in the previous edition of Formate Matters.
Reference: Van Oort, E., Ahmad, M., Spencer, R., Legacy, N.: “ROP Enhancement in Shales through Osmotic Processes”, SPE/IADC-173138-MS, March 2015.
Formate brines greatly improve ROP in shales. Arrows indicate the improvement gained by switching from WBMs to formate brines