Matrix stimulation of high-temperature sandstones using hydrochloric acid (HCl) is difficult to achieve due to its fast reaction, possible sand deconsolidation, clays destabilization, and tubular corrosion. These problems are common in stimulating wells completed across the Pinda formation in West Africa. This formation is a multilayered formation with a wide range of carbonate content (varying from 2% to nearly 100%) and bottomhole temperatures in the range of 300°F. In addition, most of the wells have up to 1,500 ft of perforated intervals producing together from different layers. Stimulation treatments in the area historically have been performed using 7.5% HCl pumped through coiled tubing and using foam diversion. In 2008 a different approach was taken to stimulate producing zones across this formation, using a low-pH chelant (pH 4) as the main stimulation fluid and straddle or inflatable packers for mechanical diversion, whenever applicable. Six wells were treated in a stimulation campaign using the chelant solution. Mechanical diversion was used in three of the six wells treated; two were treated with a mechanical straddle packer and one with an inflatable packer. Low bottomhole pressure (BHP) or wellbore configuration precluded the use of mechanical diversion for the other three wells; foam diversion was used instead. The results of these stimulations were encouraging, with the combined production of all six wells almost doubling. The good post-job results confirm the effectiveness of low-pH chelant in stimulating carbonate and carbonate-rich sandstones at high temperature, with the added value of low corrosion rates and reduced risk of sand deconsolidation and clays destabilization. This stimulation campaign also tested current technological limits of mechanical and inflatable packers. The combination of high expansion ratio, low BHP, and high temperature requirements precluded the stimulation of three of the six wells with mechanical diversion. With the increasing need to stimulate depleted high-temperature formations, these challenges must be addressed in the future.

The Alba reservoir (located in the Central N Sea) is a highly permeable, unconsolidated sand body with lenses of reactive shales within the reservoir sand. From the initial decision to exploit the field using horizontal wells there has been an evolutionary approach to selection of the most appropriate drilling fluid and completion technique. The development of the field has been marked by a drive to increase productivity and reduce the total cost of the ownership of the asset. The major challenges in completing wells on this field involve issues of sand control and inhibition of reactive reservoir shales. Initially, completions were prepacked screens in open hole and the fluid used to drill the reservoir section was oil based mud. Productivity was lower than expected but improvements were achieved by switching to sized salt water based mud and initiating a very stringent QC procedure for the drilling and completion fluids. However, screen failure occurred very soon after the wells became water cut and the wells almost invariably sanded up. More recent changes have involved a switch to sized calcium carbonate water based mud and open-hole gravel packs. Because the geology of the Alba field dictates that there is almost always some shale exposed in the open hole reservoir section it was found that the gravel carrier fluid needs to be equally as inhibitive as the drill-in fluid Since 1998 thirteen open-hole gravel packs have been successfully completed, in all cases with high flowrates and no history of sand production. This paper deals with the performance of the various techiques applied and details the best practices derived for optimum productivity and screen longevity. Introduction The Alba field is located in block 16/26 of the UK sector of the N Sea.This oil field lies above the huge Britannia gas field and comprises an Eocene sandstone formation that is thin, highly porous, highly permeable, very unconsolidated and overlain by a bed of impermeable, highly reactive shale. The nature of the reservoir dictated that development would be best achieved by open-hole completions and highly deviated or horizontal reservoir sections with the productive interval being sited near the top of the sand body. It was expected that drilling in the reservoir section would be through reactive shales and unconsolidated sand, thus three high priority requirements were perceived to be: shale inhibition and borehole stability while drilling and sand exclusion while producing. These aspects have continued to be of great importance throughout all of the evolutionary steps in the exploitation of this reservoir. During the development of this field since 1994 three drill-in fluid systems have been used:Synthetic oil based mud (SBM)Sized sodium chloride water based systemSized calcium carbonate water based system Also, three main sand control techniques have been used for production. These are:Dual wire-wrapped, pre-packed, stand-alone screensAll-metal stand-alone screensAll-metal screens and gravel pack. In respect of open-hole gravel pack two variations have been used. These were;Water based drill in fluid and water based gravel carrier fluidSBM drill in fluid and water based gravel carrier fluid The second variation is the subject of another paper 1 Huge benefits in respect of screen longevity have been obtained by adopting gravel packing as the standard completion method.

The Alba reservoir (located in the central North Sea) is a highly permeable, unconsolidated sand body with lenses of reactive shales within the reservoir sand. From the initial decision to exploit the field with horizontal wells, there has been an evolutionary approach to selecting the most appropriate drilling fluid and completion technique. Field development has been marked by a drive to increase productivity and reduce the total cost of the ownership of the asset.The major challenges in completing wells in this field involve sand control and inhibition of reactive reservoir shales.Initially, completions were prepacked screens in open hole, and the fluid used to drill the reservoir section was oil-based mud (OBM). Productivity was lower than expected, but improvements were achieved by switching to sized salt water-based mud (WBM) and initiating a very stringent quality-control procedure for the drilling and completion fluids. However, screen failure occurred within 2 to 3 years of production startup, and the wells almost invariably sanded up. More recent changes have involved a switch to sized calcium carbonate WBM and openhole gravel packs.Because the geology of the Alba field dictates that there is almost always some shale exposed in the openhole reservoir section, it was found that the gravel-carrier fluid needs to be equally as inhibitive as the drill-in fluid.Since 1998, 13 openhole gravel packs have been successfully completed, with high flow rates and no history of sand production in all cases. This paper deals with the performance of the various techiques applied and details the best practices derived for optimum productivity and screen longevity. * ChevronTexaco internal report, Houston (1997).