Early exploration well tests in the Colville River Field (also known as Alpine) drilled with water-based mud systems exhibited unexplainably high near-wellbore residual skin damage as documented by pressure buildup testing. Typical formation damage mechanisms including clay reactions, mechanical damage, and gas trapping could not explain the damage.
Between March 1998 and July 2001, laboratory testing determined imbibition-induced water trapping to be the primary formation damage mechanism. Insitu water saturation is significantly lower than the residual or connate water saturation, a condition rarely encountered in the field. Lab tests quantified impacts and identified methods to minimize or eliminate formation damage. This paper documents how successful identification of a unique damage mechanism improved drilling results in a low permeability sandstone.
Exploration drilling results in Colville River prospects consistently demonstrated higher than expected near wellbore skin damage as measured by build-up test analysis. Investigations into more common damage mechanisms such as solids migration and clay swelling could not explain the damage. Early reservoir core studies indicated residual water saturations from relative permeability curves should be higher than observed initial water saturations. Later studies with traced core confirmed initial water saturations were considerably less than normal connate water saturations. Further lab work confirmed the water-blocking tendency by measuring water imbibition and permeability recovery during regain permeability tests. Various drilling fluids were tested, with oil muds consistently delivering lower permeability losses than water based fluids.
For a number of operational reasons, all wells on the first development pad (CD1) were drilled with brinebased fluids. The second pad (CD2) development team accepted the lab results and after demonstrating the potential benefits of oil based mud drilling, convinced the Drilling team to develop and test a suitable mud program. Initial test results confirmed the lab results and conclusions when well CD2-47 came in flowing 300% more than predicted, based on equivalent brine-based mud completions in comparable pay to date. Following this early success, the oil mud program was expanded and has consistently delivered more productive wells in line with expectations from the lab work.
The Colville River Field (also known as the Alpine Field) is located approximately 60 miles due west of the Prudhoe Bay Field on the north slope of Alaska (see Figure) 1 1,2.
It contains 429 MMSTB of recoverable reserves, with approximately 1 billion barrels of oil-in-place. Production is from the Alpine Oil Pool, a very fine-grained Jurassic age shallow marine sandstone complex with stratigraphically trapped 40 ° API oil. The reservoir is normally pressured and undersaturated. Initial reservoir pressure is approximately 800 psia above the bubble point, and primary recovery mechanism is solution drive. Tables 1 and 2 (below) present a log and petrophysical overview as well as a summary of key reservoir properties.
The field was discovered in 1994 with drilling of the Bergschrund No. 1. Further delineation confirmed the prospect during subsequent winter seasons, and gravel pad construction began during the 1998 winter season. Field construction for the processing facilities and pipeline infrastructure commenced in the winter of 1999, followed closely by development drilling in May, 1999.
