Summary Early exploration well tests in the Colville River field (also known as the Alpine reservoir) drilled with water-based mud (WBM) systems exhibited unexplainably high near-wellbore residual skin damage 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. In-situ water saturation is significantly lower than 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 low-permeability sandstone.
Introduction Exploration drilling results in early Colville River prospects consistently returned higher than expected near-wellbore skin damage measured by buildup-test analysis. Investigations into more common damage mechanisms, such as solids migration and clay swelling, could not explain the damage. Early concerns over water imbibition stemmed from relative-permeability response developed during reservoir-core studies, which indicated observed initial-water saturations were significantly less than expected residual-water saturations. Later studies using traced core fluids confirmed that initial-water saturations were considerably less than natural connate-water saturations, which would be expected for strongly water-wet formations in capillary equilibrium with a free-water contact. Follow-up 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-based muds (OBMs) consistently delivering greater regained permeability than water-based fluids.
For a number of operational reasons, all wells on the first development pad (CD1) were drilled with brine-based fluids. As drilling commenced on the second pad (CD2), production engineers reviewed the lab results and, after demonstrating the potential benefits of OBM drilling, convinced the drilling team to develop and test a suitable mud program. Field experience confirmed the lab results and conclusions when a newly drilled well, CD2-47, came in flowing 300% of predicted rates based on brine-based mud completions in comparable pay. Following this early success, the OBM program was expanded and has consistently delivered more productive wells in line with lab-derived expectations.
Background The Alpine reservoir of the Colville River field is approximately 60 miles west of the Prudhoe Bay field on the North Slope of Alaska (see Fig. 1).
This reservoir contains 429 million STB of recoverable reserves, with approximately 1 billion bbl 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 DEGREE API oil. The reservoir is normally pressured and undersaturated. Initial reservoir pressure is approximately 800 psi above the bubblepoint, and the primary recovery mechanism is solution drive. Tables 1 and 2 present a log and petrophysical overview, as well as a summary of key reservoir properties.
The field was discovered in 1994 with the drilling of Bergschrund No. 1. Further delineation confirmed the prospect during subsequent winter seasons, and gravel-pad construction began during the 1998 winter season. Field construction of processing facilities and pipeline infrastructure began in the winter of 1999, which was followed closely by development drilling in May 1999. Major process modules arrived in March of 2000, and first oil was delivered in November.
The development strategy uses horizontal completions in a direct line-drive configuration, while maximizing recovery through application of pattern waterflood and miscible water-alternating-gas injection.
Early Exploration Results Following the early success of the Bergschrund No. 1 discovery well, additional wells were drilled during the winters of 1995 and 1996 to further delineate the reservoir and define reservoir properties. Geologic cores and bottomhole-fluid samples were collected from two of the earliest wells: Neve 1 and Alpine 1A. Because of the brief Arctic-winter exploration season, only select wells were production tested. Upon completion of production testing, a pressure build-up test was conducted to observe pressure build-up response of the reservoir. Early well results indicated higher levels of formation damage than routinely observed in North Slope wells. Table 2 lists results from early well testing.