An Evaluation of Perforating Techniques and Use of Caesium Formate Kill Pills to Optimise Productivity in HPHT Gas Wells and Minimise HSE Risks

Self Cite

Formate brines have been in use since 1995 as non-damaging drill-in and completion fluids for deep HPHT gas condensate field developments. The number of HPHT fields developed using formate brines now totals more than 40, and includes some of the deepest, hottest and highly-pressured reservoirs in the North Sea. The well completions have been both open-hole and cased-hole.An expectation from using formate brines as reservoir drill-in and completion fluids is that they will cause minimal damage to the reservoir and help wells to deliver their full productive potential over the life-time of the field. The validity of this expectation has been tested by examining the long-term hydrocarbon production profiles of eight HPHT gas condensate fields in the North Sea where only formate brines have been used as the well completion fluids. In five of these fields the wells were drilled with oil-based muds and completed by perforating in cased hole with high-density formate brines. In another two of the fields the wells were drilled with formate brines and completed with screens entirely in open hole using the same brines.The last of the eight fields was drilled with formate brine and the wells were then completed with same fluid in either open hole or cased hole.The results of the production analysis provide a unique insight into the impact of a single type of specialist drill-in and completion fluid on the rate of recovery of hydrocarbon reserves from deeply-buried reservoirs in the North Sea.

Section: Years Of Productionmentioning

confidence: 99%

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

Olsvik

Howard

Downs³

2013

Self Cite

Observations on Gas Permeability Measurements under HPHT Conditions in Core Materials Exposed to Cesium Formate Brine

Downs

2009

Natural gas in its native environment is in thermodynamic equilibrium with the connate liquid water phase and will be saturated with water vapour at reservoir conditions. Full water saturation of gases used in laboratory core flooding tests may not always be achieved, and it is known that the use of dry gas in such experiments can artificially reduce core permeability to gas by dehydrating and crystallising any brine residues left within the cores. This problem of permeability impairment, as a result of water vaporisation by gas, might be expected to become more acute or evident in laboratory tests with high-pressure high-temperature (HPHT) reservoir cores containing high salinity formation brine and high-density completion brine filtrates. These brines may contain salt concentrations that are already close to saturation levels and are more susceptible to crystallisation by dehydration. The objective of the work described in this paper was to look at the effect of gas humidification levels on the gas permeability of North Sea HPHT reservoir core material exposed to high-density cesium formate brine under HPHT conditions in laboratory core flooding experiments. The results from core flooding experiments at 200oC (392oF) indicated that full HPHT-humidification of the gas phase resulted in a higher gas return permeability when compared with a test using gas humidified at room temperature and high pressure. This finding highlights the importance of ensuring that any gases used in HPHT core flooding tests are fully saturated with water vapour at the test temperature and pressure. It seems likely that the impact of gas humidification levels will be amplified in very low permeability cores subjected to high drawdown pressures. Introduction Natural gas contains a variety of non-hydrocarbon contaminants. These contaminants include water vapour. In its native reservoir environment the gas is in thermodynamic equilibrium with the connate liquid water phase and will be saturated with water vapour at reservoir conditions [Rushing, et al, 2008; Udell, 1982; Zuluaga and Monsalve, 2003]. The amount of water vapour present in the gas phase is a function of the gas composition, reservoir pressure, reservoir temperature and the dissolved salt content of the connate water. The water content of the gas increases with increasing temperatures, but an increase in pressure or dissolved salt content has the opposite effect.

A Review of the Impact of the Use of Formate Brines on the Economics of Deep Gas Field Development Projects

Downs

2010

The technical difficulty of constructing deep gas wells makes them costly items on any operator's budget sheet. For this reason there is a powerful economic driver for the operator to use the best available well construction technologies that will deliver a deep gas well at lowest overall cost while ensuring that the well's connectivity to recoverable hydrocarbons is not impeded in any way. In 1995 Mobil was the first oil company to use formate brines as drill-in and completion fluids to improve the economics of deep gas field developments. Since then the formate brines have been used in more than 30 deep gas projects (amounting to at least 140 wells) by major oil companies such as Total, Statoil, BP and Saudi Aramco. These developments have included the deepest reservoir in the North Sea and the largest HPHT gas field in the world. This paper collates and categorises all of the statements relating to the performance of high-density formate brines in deep gas well constructions, as recorded in a number of white papers written by three long-term users of the brines. A review of these statements provides an insight into where and how the formate brines are delivering economic benefits in deep gas field developments. This analysis is complemented by a look at the production performance of two deep HPHT gas fields drilled and completed with formate brines in 2001/02. The cumulative hydrocarbon production from these fields is now already close to or exceeding 90% of estimated recoverable reserves. The weight of evidence, supported by the sustained demand for formate brines in these applications over a period of 14 years, suggests that the use of formates introduces economies and efficiencies into deep gas field developments that are a) worth more in value than the overall cost of owning or leasing the brine and b) more rewarding than those provided by alternative well construction fluids.