Summary
The BP-operated Miller field poses a unique chemical challenge because it
has arguably the harshest oilfield scaling regime in the North Sea, if not the
world. An average of three to four squeeze treatments per week are performed
across the online wells, creating tremendous operational, chemical, and
logistical challenges. This produces the ideal environment in which to evaluate
new technologies and engineering solutions in an attempt to increase the wells’
overall efficiency.
Deep downhole chemical injection (DDHCI) was installed on Well A26/08 and
brought on line in July 2003. The Miller DDHCI is unique to the industry
because it allows the injection of a scale inhibitor at the perforations by
means of a tail pipe, essentially protecting the whole of the tubing from scale
deposition. This approach has the potential to reduce the need for additional
scale control through squeeze treatments.
Much emphasis has been placed on the efficiency of scale protection that
DDHCI offers. A year of flowing the well under the protection of the
continuous-injection chemical has yielded much information about the nature of
the chemical delivery and inhibitor efficiency. Much also has been learned
about the pumping hardware required to ensure continued performance. Further
information has been provided by two intensive sampling exercises that have
allowed independent analysis of the squeeze chemicals and the injected
chemical.
This paper details the design criteria of the DDHCI completion as well as
the philosophy of installing such a device. It then gives details on the
management strategy of using DDHCI in a proactive manner to maximize the time
between squeeze treatments.
Miller Field Background
The BP-operated Miller field is located in the U.K. Sector of the North Sea
in Blocks 16/7b and 16/8b, approximately 145 miles north/northeast of Aberdeen.
The field produces both gas (exported down the Miller Gas Pipeline to
Peterhead) and oil (exported through the Forties Pipeline System to
Grangemouth). There are 10 producer wells; first oil occurred in 1992 and
leveled off in 1993 at 140,000 BOPD. Water and gas injection was initially
through six injector wells; it began approximately 1 year after first oil and
peaked at 300,000 BWPD.
Steady decline has occurred since 1997 and was contemporaneous with high and
sudden water breakthrough. Currently, the field potential is 16,000 BOPD, and
water-production potential is 80,000 BWPD. In spite of this, the field has
achieved its original recoverable reserves, having produced a little more than
340 million bbl of oil. Cessation of production (COP) is currently expected to
be December 2006 on the basis of recent low-oil-throughput flow trials.
The most significant aspect of the Miller is the barium content of its
formation water. This is summarized in Table 1, and it is the 650-ppm barium
figure that stands out. This figure was determined from the initial
preproduction samples; since then, a range of barium concentrations has been
detected at surface, with a maximum being more than 3,500 ppm.
© 2006. Society of Petroleum Engineers
View full textPDF
(
658 KB
)
History
- Original manuscript received:
30 November 2004
- Revised manuscript received:
2 September 2005
- Manuscript approved:
9 September 2005
- Version of record:
20 May 2006
View Cart
