Exploration in the Sable Sub-basin shelf is relatively immature and still holds surprising near-field exploration prospectivity around the Sable Offshore Energy Project (SOEP) infrastructure. Shell and partners have drilled 19 exploration wells on the current Shell interest leases in the Sable Sub-basin from 1969 to 2001 and have discovered nearly 1BBOE. Exploration proceeded in 3 phases, an early phase of hydropressure exploration, a main phase of deep geopressure exploration, and a later phase of exploration in geopressures.
The early phase of exploration in hydropressures involved 5 wells from 1969 to 1975. Onondaga E-84, Triumph P-50, Thebaude P-84, Citnalta I-59, and Intrepid L-80 tested reservoir objectives ranging from the Late Jurassic MicMac Formation to the Early Cretaceous Upper Missisauga Formation. The discovered volume totaled 1.2 Tcf and 36MMBC. Drilling was suspended at the top of geopressures. Success at the top of geopressures in the Thebaude well encouraged deeper drilling in geopressures.
Discovery of the 1.5 Tcf Venture field in 1978 kicked off a phase of successful deep exploration in geopressures. Another 11 deep wells were drilled through 1985 and discovered another 2.65 Tcf in a series of moderate sized gas fields ranging from 130 to 437 Bcf. These fields include Arcadia, Glenelg, Olympia, Venture, South Uniacke, Alma, Chebucto, Venture West, and Triumph North. Hydrocarbons, primarily gas, were found in both geopressured and hydropressured reservoirs that ranged in age from the Late Jurassic to the Early Cretaceous.
The final phase of exploration resulted in only two wells since 1985, Sable South B-44 and Onondaga B-84, both resulted in discoveries. Most of the industry exploration in the basin since 1985 has focused on carbonate, not clastic plays.
The next phase of exploration remains to be tested by the drill bit. Fifty-five leads have been defined in the Sable Sub-basin around the Sable Offshore Energy Project (SOEP) infrastructure. All the leads are downthrown fault closures with shelf margin delta complexes as reservoirs. The combined factors of rapid subsidence, high sediment input from a large river, and proximity to the shelf margin result in thick geopressured reservoirs with multiple intra-formational seals and thick top seals. Fault closure traps occur along faults with large throw with potentially long columns. Several geopressured traps in the discovered fields have fault dependent columns ranging from 100m to 205m.
In conclusion, considerable scope for near field exploration is present in the Sable Sub-basin in conventional plays that have not been extensively explored since 1985.
This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 19273, "The Offshore Petroleum Industry in Atlantic Canada - A Regional Overview," by R.P. Barnes, Canadian Association of Petroleum Producers, prepared for the 2008 Offshore Technology Conference, Houston, 5-8 May. The paper has not been peer reviewed.
Twenty-four oil and/or gas discoveries have been made offshore Newfoundland and Labrador. Three of the oil discoveries have been developed and a fourth is under consideration. The focus of development activity has been on the larger oil discoveries. As production from the larger discoveries matures, facilities and other infrastructure will become available for development of the remaining smaller discoveries. Development and tie-in of smaller pools and fields provides an opportunity to utilize this spare production capacity at these fields. Currently, there are several satellite tie-in and expansion projects in progress and others are under review. Development of the discovered smaller fields will play an important part in sustaining production from offshore Newfoundland and Labrador. In addition, many of the offshore basins are under explored and represent other opportunities to supply the next round of developments.
Newfoundland and Labrador, Canada's easterly province (Fig. 1) is strategically positioned on international shipping lanes, with unique access to global petroleum markets.
This paper will give an overview of current and planned future offshore exploration, development and production activity taking place off the east coast of Canada. It will also cover other items of interest occurring in that area including industry related research and development, recent changes in government policy and future growth potential of the industry. Information provided in this paper will be of interest to petroleum supply/service companies wishing to market their goods and services in this region of Canada as it will identify what producers are active in this area and possible future growth opportunities. In addition, the information provided on petroleum related research and development taking place and being applied in the region for offshore development and production would be of interest to a technical audience wishing to apply such research and development to other producing areas.
The exploration drilling programs offshore Newfoundland and Labrador were at the forefront of technology evolution. Deep-water drilling records were set in 1979 with the drilling of Texaco et al Blue H-28 well in 1486 metres of water, and again in 1987 with the drilling of the Northcor et al Narwhal F-99 well in 1587 metres of water. Exploration drilling was the first major oil and gas activity to have to deal with ice management. During the exploration programs, industry developed and implemented procedures to operate in ice conditions, acquired environmental and ice data and conducted ice research, which are necessary for designing and operating production facilities. Drilling programs have utilized semi-submersibles or drill ships in most areas, largely as a measure to extend programs into the periods when ice is present. These units are capable of moving off location quickly if threatened by ice.
Disposal of oil-contaminated cuttings has become increasingly important from both economic and environmental perspectives. Re-injection through hydraulic fracturing can provide a zero discharge solution and eliminate future cleanup liabilities. The development of best practices and practical solutions for predicting fracture growth during slurry injection has accelerated the economic disposal of oily cuttings from drilling operations.
One such case is for Panuke wells, in Nova Scotia, Canada. For sections deeper than 1290 m MD, these wells are drilled with oil based mud. In the past, drilling waste was injected into an existing well, Well PI-1. A total cuttings slurry volume of 96,000 bbls had been injected through casing into well PI-1 before an additional well was planned in early 1999. Well PP3C was identified as a candidate injection well through the 11¾" ( 9 5/8" casing annulus. In order to assure the containment of fractures arising from injection, investigations were conducted on the design of the injection process using a fully three-dimensional hydraulic fracturing simulator. This paper assesses the affects of formation layering, varying permeability and elastic modulus, injection rate, and other operational procedures on the injection fracture geometry and containment.
Significant to the injection recommendations were lessons learned from a recent joint industry project on ‘drilling waste disposal' (DEA #81). The ability to verify multiple fractures in DEA #81 from post laboratory test examination suggests that the analyses and design are adequate to assure safe containment of injected drill cuttings. The case study showed that interaction among the various factors can result in very complex fracture geometry and a true three-dimensional fracturing simulator must be used to assess fracture containment. The results provide insight into best practices for the containment of fractures, designs for successful re-injection, selection of candidate injection zones, and quality assurance.
Re-injection of oil-contaminated drill cuttings is attracting considerable attention as a cost-effective means of complying with environmental legislation concerning discharges of drilling waste. Cuttings slurry re-injection through casing annulus was established in Alaska (Abou-Sayed et al.), 1 the Gulf of Mexico (Malachosky et al.,2 and Louviere and Reddoch3), the Gyda/Ula field in Norway (Willson, Rylance and Last)4 and in many other parts of the world.5 Oily-cuttings slurry re-injection techniques using hydraulic fracturing have been successful and have led to the adoption of the technique as a routine disposal method. For a twenty well program in the Gyda/Ula Field, economic analysis showed that, re-injection of cuttings slurry would cost approximately $9.6 million versus $18 million for onshore processing and $39 million for using water-based mud (Minton and Last).6
To ensure that cuttings re-injection through hydraulic fracturing is environmentally safe, containment of injected waste must be assured. Careful evaluations must be carried out to determine where to inject the drill cuttings slurry and how much slurry can be injected into each well. A fully three-dimensional fracturing simulator is necessary for characterizing different factors such as in-situ stress, Young's modulus, leakoff, location of injection or location of initial fracture, as well as the influence of injection rate on fracture dimensions and consequently the maximum allowable slurry volume.