Cesium formate brine is heavy low-viscosity clear fluid, designed specifically to provide the oil industry with better and safer well control in HPHT field operations. Cesium formate brine can be safely deployed for long periods in extreme HPHT wells where traditional well control fluids would cause major problems. Field experience in the Mako-6 well (BHST: 235˚C/455˚F) in Hungary shows that suspension fluids based on buffered cesium formate brine tolerate months of exposure to a combination of extreme temperatures/pressures and acid gas influxes.

Formate brines have a long history as suspension and packer fluids for HPHT wells:

1996: Shell pioneers potassium formate brine as packer fluid in Dunlin well A-14, retrieving the 13Cr tubular after two years in perfect condition.

2002: BP uses 11.5 lb/gal sodium/potassium formate brine as packer fluid in High Island well A-5. The 13Cr tubular was retrieved in remarkably good condition after six years exposure to the brine at 163˚C (325˚F). Read the full article here.

2004: Saudi Aramco suspends a screen-completed HPHT gas well for three years with sodium/potassium brine. In 2007, a production build-up survey confirms a completion skin of < 1¹. Saudi Aramco reports in 2009 that “the well continues to produce successfully at sustained, high sand-free rate”².

2001-2007: Sodium/potassium formate brines deployed as packer fluids in numerous wells in Gulf of Mexico from 2001 onwards – see Table 1³.

Table 1 – Some HPHT wells in Gulf of Mexico where formate brines have been deployed as packer fluids

Operator	Well	Packer fluid type	Density		Bottom hole temperature		Year deployed
			lb/gal	g/cm3	°F	°C
Devon	WC 165 A-7	K formate	8.6	1.03	300	149	2005
Devon	WC 165 A-8	K formate	8.6	1.03	300	149	2006
Devon	WC 575 A-3 ST2	Na/K formate	9.5	1.14	270	132	2005
Walter O&G	MO 862 #1	Na/K formate	12.0	1.44	420	215	2005
BP/Apache	HI A5 #1	Na/K formate	11.5	1.38	327	164	2002
ExxonMobil	MO 822 #7	Na/K formate	12.0	1.44	420	215	2001
EPL	ST 42 #1	Na/K formate	11.5	1.38	272	133	2006
EPL	ST 41 #F1	Na/K formate	13.0	1.56	222	105	2006
EPL	EC 109 A-5	Na/K formate	11.5	1.38	250	121	2006
EPL	ST 42 #2	Na/K formate	12.8	1.53	270	132	2006
Dominion	WC 72 #3 BP1	Na formate	10.0	1.20	250	121	2006
EPL	WC 98 A3 ST1	Na/K formate	12.7	1.52	307	153	2006
EPL	WC 98 A3	Na/K formate	10.8	1.29	310	154	2007

Long-term suspensions

Since 1999, cesium formate brine has been used to suspend wells in eleven HPHT fields (see Table 2). Wells in the Tune, Kvitebjørn and Vega fields have been suspended for six to 12 months with potassium/cesium formate brines left across open-hole sand-screen completions. This extensive and prolonged use of cesium formate brine in well suspensions has confirmed its clear advantages over traditional high-density intervention fluids:

Reduced formation damage – cesium formate seems to be incapable of causing permanent formation damage. Most users report that their well productivity indices exceed expectations after long exposure to cesium formate brine during suspension operations. Statoil’s Huldra and Tune wells are good examples. Read more here.

New improved HSE standards and reduced liability – no other high-density brines come close to matching the high HSE standards set by cesium formate. Using cesium formate brine avoids compromising safety and greatly reduces risk of long-term liability.

Improved well integrity – buffered cesium formate brine reduces risk of catastrophic localised corrosion and stress-corrosion cracking in well tubulars exposed to HPHT acid gas influxes.

Table 2 – HPHT fields with gas/condensate reservoirs where cesium formate brines have been used as long-term well suspension fluids

Operator / Field	Max. temp.		Completion material	Liner mat.	Packer mat.	Brine density		Reservoir pressure		CO2	H2S	Suspension time
	°C	°F	CRA	CRA	CRA	g/cm3	lb/gal	MPa	psi	%	ppm	days
BP Rhum	149	300	S13Cr	S13Cr	718	2.00-2.20	16.69-18.36	84.8	12,300	5	5-10	250
Shell Shearwater	182	360	25Cr	25Cr	718	2.05-2.20	17.10-18.36	105.6	15,320	3	20	65
Marathon Braemar	135	275	13Cr	22Cr	718	1.80-1.85	15.02-15.44	74.4	10,800	6.5	2.5	7
BP Devenick	146	295	13Cr	VM110	718	1.60-1.65	13.35-13.76	72.4	10,500	3.5	5	90
Total Elgin/Franklin	204	400	25Cr	P110	718	2.10-2.20	17.52-18.36	115.3	16,720	4	20-50	723
Statoil Huldra	149	300	S13Cr	S13Cr	718	1.85-1.95	15.44-16.27	67.5	9,790	4	10-14	45
Statoil Kvitebjørn	155	311	S13Cr	13Cr	718	2.00-2.06	16.69-17.19	81	11,700	2-3	Max. 10	448
Statoil Kristin	171	340	S13Cr	S13Cr	718	2.09-2.13	17.44-17.77	90	13,000	3.5	12-17	57
Statoil Vega	135	275	S13Cr	S13Cr	718	1.62	13.51	_	_	_	_	300
Norsk Hydro Tune	131	268	13Cr	_	718	1.65	13.76	52	7,614	_	_	365
TXM Mako	235	455	L80	P-110	22Cr	2.15	17.94	96	14,000	30	150	180

References

1. Morgan, Q.: “Expandable Sand Screens achieve neutral skin in deep, hot and corrosive gas well after three-year shutdown”, publication by Weatherford International, 2008.
2. Ginest, N., et al: “A Successful Expandable Sand Screen Case History in a Deep, Corrosive Gas Well Application”, SPE 122847, May 2009.
3. King, L. and Benton, W.: “Cracking Protection”, Oilfield Technology, August 2009.