Life Without Barite: Ten Years of Drilling Deep HPHT Gas Wells With Cesium Formate Brine

Abstract

The tradition of using barite to increase the weight of drilling fluids dates back to the early-1920's and, while it has been of great benefit to the oil industry over the past 90 years, it has also caused some chronic and persistent well construction problems along the way. These problems, which are very familiar to drillers, include well control difficulties, stuck pipe incidents and formation damage.The oil industry has known since the 1970's that replacing barite with suitable non-damaging solutes in reservoir drill-in fluids is an effective way of reducing formation damage, simplifying operations and eliminating the need for expensive formation damage by-pass operations. The development of brine-based drill-in fluids opened up the opportunity to connect more effectively with hydrocarbon reserves by allowing the construction of long high-angle reservoir sections completed in open hole. Despite the advantages on offer, the industry was unable to exploit this novel technology in deep HPHT gas field developments until the mid-to late-1990's when drill-in fluids based on potassium and cesium formate brine became available in commercial volumes.Cesium formate brine was first used as a reservoir drilling fluid in the Huldra gas/condensate field in the North Sea in January 2001, and has now been used to drill a total of 29 deep HPHT gas wells. The information presented and reviewed in this paper confirms that the use of potassium and cesium formates as the sole weighting agents in reservoir drill-in fluids has enabled operators to enjoy the full economic benefits of creating low-skin open-hole completions in deep high-angle HPHT gas wells. The review also concludes that the use of these heavy formate brines as drill-in fluids over the past 10 years has facilitated the safe and efficient development of deep HPHT gas reserves by:• Virtually eliminating well control and stuck pipe incidents • Enabling the drilling of long high-angle HPHT wells with narrow drilling windows • Typically reducing offshore HPHT well completion times by 30 days or more • Improving the definition and visualization of the reservoirs • Eliminating the need for clean-ups, stimulation treatments or any other form of post-drilling well intervention to remove formation damage caused by the drilling fluid This has all been made possible by the operators' acceptance and adoption of the award-winning Chemical Leasing (ChL) and fluid management programmes that form the basis of their contracts with the sole producer of cesium formate brine.BP Devenick 1 385 4,560 <1 135 Petrobras El Campamento 1 650 --126This paper begins by providing a summary of these operations, field by field, and looks in some detail at the original drilling campaign in Huldra. It then lists some key highlights from ten years of drilling deep HPHT gas wells with barite-free cesium formate brine. The paper concludes that the use of cesium formate brine as a reservoir drill-in for deep gas field development enhances well construction efficiency, well safety and well productivity. Su...

Nanomaterial-Based Drilling Fluids for Exploitation of Unconventional Reservoirs: A Review

“…This problem results from loss circulation, torque and drag, equivalent circulation density (ECD) fluctuations, and also due to operation that requires drilling fluid to be static for long time. Downs et al [95] have observed that high loading of barite in typical drilling fluids increase frictional pressure losses when circulating in long sections, leading to unacceptably high ECD in narrow operating drilling windows (where pore pressures and fracture pressures are very close to each other). The solids-carrying function of conventional drilling fluid can be deteriorated, triggering dynamic and static barite sag, and intensifying the risk of losing well control in the case of high angle wells.…”

“…Oil-based drilling fluid is normally chosen for HPHT drilling as a means of tackling high temperature conditions because it is stable to at least 450 • F in 16-h laboratory tests [101], it typically exhibits a lower coefficient of friction, and it provides a thinner and more lubricious filter cake [102]. Some drawbacks of OBDF are: (1) high cost, (2) influence on logging interpretation, (3) OBDF can absorb a large amount of gas, (4) environmental issues, and (5) the thermal expansion of OBDF is higher than WBDF, which can lead to pressurization of the annulus [95,101]. For example, invert emulsion system drilling fluid is environmental friendly and it has better thermal stability (up to 478 K); thus, it can be used to drill HPHT wells [103].…”

Formate Drilling and Completion Fluids: Evaluation of Potential Well-Productivity Impact, Valemon

“…The third technique used, microCT, is a relatively recent addition to formation-damage evaluation. It provides much greater resolution when compared to CT scanning and allows a 3D visualization of the pore structure, such that any changes occurring after testing could be detected by the density contrast (Green et al 2013). …”

“…Formate brines have been used over a number of years as drilling-and-completion fluids for HP/HT fields (Howard 1995;Bungert et al 2000;Saasen 2002;Simpson et al 2005;Oswald et al 2006;Berg et al 2009;Qureshi et al 2008;Downs 2011;Olsvik et al 2013). Olsvik et al (2013) summarized the results from eight HP/HT fields in which cesium formate was used as the completion fluid in conjunction with a cesium-formate drilling fluid or oil-based mud.…”

The Long-Term Production Performance of Deep HPHT Gas Condensate Fields Developed Using Formate Brines

“…Over the past 18 years formate brines have been used as reservoir drill-in and completion fluids in more than 40 HPHT gas condensate field developments, accessing some of the deepest, hottest and highest-pressured reservoirs in Europe [Downs, 2010;Downs, 2011]. The UK and Norwegian governments publish monthly updated figures for the gas and condensate production from fields in their sectors of the North Sea.…”