Understanding steam assisted gravity drainage (SAGD) drilling performance allows operators to focus on achieving cost control. In a recently released comparative SAGD drilling and cost benchmarking study, Ziff Energy Group examines the efficiency level achieved by in situ (or in-place) programs.
SAGD projects are attractive to producers in comparison to oil sands operations, which cost billions of dollars, because the SAGD process can access deeper formations and be developed on a smaller scale. The process also can be developed in phases, which sharply reduces the capital required as well as the engineering and construction risks.
However the process is evaluated, the fact is that drilling and completion costs on SAGD and delineation wells are significant. And having an understanding of those costs benefits operators.
Study parameters
Ziff Energy Group’s first Drilling Benchmarking Study provides an independent detailed analysis of the drilling and completions costs on SAGD and delineation wells
for oil sands properties in the Western Canadian Sedimentary Basin for the period from late 2004 to fall 2008.
The study assessed 159 SAGD well pairs and 1,833 delineation wells. Of US $986 million spent, more than half was on the shallow delineation programs. Clients of the study included five international operators and two Canadian operators.
This analysis is especially important because today the oil sands are one of the few positive growth stories for oil supplies available to the US from a politically “safe” country. Oil sands operations have been in the news quite a lot (unfortunately, in some cases, as the target of environmental groups). In contrast to oil sands mining, SAGD has a very small environmental footprint, and the numbers generated in this study indicate SAGD operations can be quite profitable.
SAGD is an in situ process to produce oil from bitumen that is too deep to mine, normally deeper than 500 ft (152 m). Because the SAGD process can access deeper formations and be developed
on a smaller scale, very small producers can undertake a SAGD project. In situ SAGD is predicted to grow faster than mining operations from 2009 to 2020. In fact, Ziff Energy estimates SAGD production will overtake mining production by 2030. Over the same time frame, a significant decline is expected in Canadian East Coast conventional oil (-20%) and offshore (-10%).
SAGD oil sands projects
The SAGD process involves sophisticated onshore drilling of a two-well pair — one above another with exactly 16.5-ft (5-m) separation. The top well is the steam injector, and the bottom well is the oil producer. Between four and 20 well pairs are drilled from one well pad. All of the well pairs are drilled parallel to one another about 330 ft (100 m) apart, with half of the well pairs oriented in one direction and the other half typically oriented 180° in the opposite direction to maximize reservoir coverage.
The 16.5-ft separation has proven to be the optimal gap to maximum reservoir production, resulting in the most effective impact from the injected steam. The study found that although the separation between injector and producer wells is planned for 16.5 ft, some wells had gaps as great as 26 to 30 ft (8 to 9 m) between injector and producer wells at some points, which reduced production capability from that zone.
The sequence for drilling the well pairs is generally a batch process, with all of the producer wells on the pad being drilled first, followed by all of the injectors. Operators drill injectors with the assistance of “ranging tools,” which aid in precisely tracking the wellbore of the lower producer to achieve the desired 16.5-ft spacing.
The first part of any SAGD project involves drilling many hundreds of delineation wells, relatively shallow vertical wells ranging from about 650 to 2,000 ft (200 to 600 m) deep that define the reservoir and prove the reserves. Once a given area has been thoroughly “mapped” for the anticipated pay zone, companies
can design the specific pattern for the SAGD well-pair drilling program.
The SAGD process
Steam is injected into the injector well, heating the pay zone as it penetrates the formation and creating a steam chamber. Gravity drains the oil downward. The oil is produced through the producer well by means of a downhole pump. The horizontal reach from heel to toe (i.e., the start of the horizontal section to the end) is long, from 1,970 to 3,280 ft (600 to 1,000 m).
The SAGD process requires about 1,200 cf of natural gas to create enough steam to produce one barrel of bitumen. Canada’s National Energy Board (NEB) estimates US $17 to $21 of capital cost is invested to produce a barrel of bitumen via the SAGD method.
Since the main component of the operating cost is natural gas used to create steam, thermal oil producers in North America are realizing a bonanza with the current cheap gas.
The SAGD method is more environmentally benign than oil sands mining. According to a recently published report comparing thermal projects, the life cycle greenhouse gas (GHG) emissions of California thermal enhanced oil recovery were 113 g of CO2 equivalent/megajoules (MJ) gasoline, as compared to the following for two Canadian in situ oil sands synthetic crude oil blends: SAGD upgraded bitumen (116 g CO2 equivalent/MJ gasoline) and SAGD bitumen
(113 g CO2 equivalent/MJ gasoline).
Future spend
The SAGD sector will account for billions of dollars of future spending. The volatility of world oil prices, combined with the non-volatile cost inflation in the oil sands, means that maximizing efficiency of front-end capital is critical for high returns, especially the efficiency of well drilling. Because the study covered a time frame of a little longer than four years from 2004 to 2008, and because of rapid inflation in the SAGD sector of the oil and gas industry during this period, Ziff Energy Group designed an inflation index model based on statistical indices and client input to normalize all costs to 2008 dollars, thereby providing fair drilling cost comparisons for all well programs.
By comparing unit drilling cost (excluding fixed material costs such as casing and cement) vs. total depth, operators can clearly see that as depth increases, unit costs generally decrease in contrast to costs associated with deeper conventional wells.
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