Carbon dioxide production (rCO2) was estimated in four sheep over a period of 10 days using doubly labeled water (2H and 18O) and was compared with simultaneous respiration chamber measurements of CO2. The excess 2H and 18O measurements were corrected for the empirically determined effects of isotope rebreathing within the confines of the chambers. A weighted monoexponential curve was then fitted to the data from which isotope flux rates and ultimately rCO2 and water turnover (rH2O) estimates were made. The curve fits were weighted assuming a Poisson model. Selection of this weighting policy did not bias the results, and curvature in the data also appeared to have little effect on the rCO2 estimates. Fractionated evaporative water loss expressed as a fraction of rH2O (X) was estimated from water balance and breath water production estimates; the mean X was 0.145 and ranged from 0.108 to 0.183. Corrections for 2H loss in fecal solids reduced the mean rH2O (4,746 g/day) by 35.5 g/day and increased the mean rCO2 (332.3 l/day) by 21.2 l/day. Further corrections to account for 2H loss in methane (mean production rate 27.2 l/day) reduced rH2O by 33.8 g/day and increased rCO2 by 20.3 l/day. The final isotopic estimates of rH2O were 14.6 +/- 6.59% (n = 4) lower than direct measurements and the mean rCO2 was 3.5 +/- 14.48% (n = 4) lower than the chamber measured rCO2. However, in one of the animals studied the rCO2 deviated markedly from the chamber-derived value, and this discrepancy has yet to be explained. When this animal was excluded from the comparisons, the standard deviation was greatly reduced (+/- 3.6, n = 3) and the mean overall error on rCO2 was +3.6%.

The CO2 production (rCO2) of eight growing pigs was determined by continuous collection of CO2 over 21 days and simultaneously estimated using the doubly labeled water (DLW) method. The aim was to assess the accuracy of the method before and after correction for known sources of error and to test for any residual discrepancy arising from as yet unidentified sources of error. Mass spectrometer accuracy was verified by analyzing serial dilutions of the dose material in the form of an artificial decay curve; no significant bias was detected. The physiological errors were linearly dependent on weight gain. DLW-derived rCO2 (corrected only for fractionated water loss) underestimated the true value by 0.270 l CO2/g wt gain or -8% in the restricted (group R) and -16% in the ad libitum-fed (group AL) groups. Known sources of error accounted for -0.006 (methane), -0.032 (fecal 2H losses), -0.108 (fat synthesis), and -0.146 (changing pool size) l CO2/g wt gain. After correction for these sources of error the DLW-derived rCO2 differed from the true value by -2 +/- 3% in group R and 0 +/- 3% in group AL. Thus there was no significant bias in the DLW method after correction for known sources of error, even during rapid weight gain or at weight stability with or without correction. The precision estimates include both dose and background errors and uncertainty in the correction factors used. Strategies for optimizing precision are presented.

Gas lift in Terra Nova production wells serves two purposes. The first is to increase the rate at which reservoir fluids can be produced, especially as water cuts increase with time and reservoir pressure diminishes. The second is to stabilize flow in the wells, flowlines and flexible risers. This paper describes the application of engineering tools to achieve an optimized subsea gas lift design for a 6350 m3/d (40,000 bpd) production rate, taking into account reservoir, wellbore, subsea and topsides constraints. Introduction The Terra Nova development is located on the Canadian Grand Banks, 350 km (220 miles) East-Southeast of St. John's, Newfoundland. The oilfield is being developed with an ice-strengthened, double hulled, floating production-storage-offloading vessel (FPSO) and subsea wells, (Fig. 1). Subsea equipment and trees are located in large ‘glory holes’ to protect this equipment from scouring icebergs. The focus of this paper is the Terra Nova gas lift design. The prime objectives of the Terra Nova gas lift design were to determine gas lift injection rates, valve setting depths and orifice sizes that would ensure maximum well productivity. Combined well and flowline performance was analyzed using a multiphase network hydraulic simulator, which determined the maximum transport capacity of a complex well and flowline system, while ensuring that reservoir simulator, wellbore and facilities constraints were being honoured. The deliverability analysis considered the production rates, water cuts and reservoir pressures provided by reservoir simulations to explore a range of reservoir depletion scenarios, from ‘pessimistic’ to ‘optimistic’. Wellbore and flowline studies were done to ensure that gas lift rates and orifice sizes would result in stable flow in the wells, flowlines and flexible risers. This design work also investigated the potential to simplify well completions by eliminating gas lift unloading valves. Various well startup scenarios were examined. Choke discharge coefficients for the dual-check operating valves were determined in lab testing to ensure accurate modeling. 1.0 Reservoir Description The Terra Nova reservoir (Fig. 2) has been mapped as a number of large blocks, defined by major faults. Within these blocks are many smaller blocks separated by minor faults. The reservoir geological model is represented by six sand sequences and seven shale sequences. Four of the major blocks will be developed in the initial 24 well Terra Nova development. Three reservoir blocks will be developed with pressure support by waterflood. The fourth block will be developed with updip gas injection, with water-alternating-gas (WAG) as a future option. The target reservoir for this study, the North East (N.E.) block, is a syncline, with the centre dipping towards the South. Seismic has identified faults that traverse the N.E. block in an East-West direction. In addition, subseismic faulting is suspected. Water injection wells are located in the valley of the syncline, while producers were drilled updip along the West and East boundaries of the pool. Table 1 summarizes the reservoir properties. 2.0 Well Description Wells in the field were designed as 178 mm (7") monobore completions, meaning that the tubing is the same diameter as the cemented liner through the zones of interest. The monobore design facilitates future well interventions for production logging or zonal isolation. The anticipated high rates required that 178 mm tubing be selected for the producers. 178 mm tubing was also chosen for water and gas injectors to reduce friction pressure drop and maximize injectivity. A typical production well is illustrated in Figure 3. Numerous horizontal producers were originally envisioned, but high well productivities and reservoir fault location uncertainties have led to more inclined than horizontal producers being drilled.

Steam Assisted Gravity Drainage (SAGD) is an enhanced oil recovery process wherein a long horizontal steam injection well is located above a long horizontal production well. Injected steam forms a steam chamber above the SAGD well pair, heating the reservoir rock and reservoir fluids. Heated oil (or bitumen) plus condensed steam flow down the sides of the steam chamber towards the production well. The condensed steam and bitumen are then lifted to surface with a downhole pump or by gas lift. Due to a rapidly increasing number of SAGD well pairs, Suncor required a tool that could accurately model these challenging thermal production wells.Nodal analysis for well performance is based on the principle that reservoir inflow and wellbore outflow can be independently characterized as functions of flow rate and pressure. Nodal analysis is used to design new wells and optimize production or injection on existing wells. Wellbore simulations are cheaper than instrumentation, meters or single well tests. Well evaluation software is the most popular engineering package in Suncor's production engineering toolkit because it is very accurate and easy to use. Over the past few years Suncor worked with their software provider to develop nodal analysis for SAGD production wells. Suncor can now model SAGD producers with electric submersible pumps (ESPs) and gas lift with a high degree of confidence.The new SAGD nodal models quite closely match production rates, plus surface and downhole pressure and temperature data. Reliable and rigorous SAGD nodal models enable improved decisions with respect to SAGD field development and production optimization. Nodal analysis can be used as a predictive tool for production optimization, or for a better understanding of what is happening downhole with respect to temperature, pressure, and flow distribution within the wellbore. This paper is a logical continuation of SPE 170054, Nodal Analysis for SAGD Production Wells with ESPs (ref 1). The main difference between modeling wells with gas lift rather than mechanical lift is that the gas lift models also account for steam lift. Steam lift occurs when some of the produced water (PW) in the emulsion flashes to steam as pressure is reduced. The resulting vapour significantly augments gas lift and reduces lift gas requirements.

Petro-Canada operates a number of thermal and non-thermal projects in the oil sands and heavy oil areas of Eastern Alberta and Western Saskatchewan. These projects have been plagued with low pump efficiencies, slow rod fall, fluid pound, solids production and overloaded pumpjacks. Petro-Canada's solutions to these problems on steam, fireflood and primary producers in unconsolidated sand formations are presented in this paper. Specific topics include completion practices, bottomhole pump designs, sand control equipment and production techniques. Introduction Production of heavy oil, whether on primary or with the assistance of enhanced oil recovery techniques, is far more difficult than recovery of conventional light oil. Production wells at Petro-Canada have gone through many stages of development. Earlier wells were designed to obtain both production and information. Cost effectiveness, reduced maintenance and improved production were the bases of later well designs. Standardized completions have evolved for primary (Fig. 1), steam (Fig. 2) and fireflood (Fig. 3). Casings All surface casing is 244 mm. 48.1 kg/m. H-40, ST+C. Heavy oil wells use large 178 mm production casing so that sand control devices can be installed if necessary, larger tubulars can be used to reduce rod fall problems, dual completions can be considered, and conversion a f a field from primary to EOR can be readily accomplished. Primary wells are completed with 178 mm, 29.5 kg/m, K-55 ST+ C casing. The preferred casing on thermal completions is 178 mm, 34.2 kg/m, MN-80, Buttress, landed in tension but not prestressed. Fireflood wells use non-exotic alloys for all of the wellbore except across the zone of interest, where nickel alloys are run. Cements Good cement bonds, with minimal loss of cement into formations are the main objectives of Petro-Canada's cementing programs. A typical primary cement would consist of Class "A" + 3% CaCl2 for the surface casing, 2: 1:4 Pozmix for the upper 70% of the production casing, and Class "G" + 3% KCl for the lower 30% of the production casing. Fireflood wells subsitute Ciment Fondue, extended with alumina silicate firebrick, for the lower 30% of the production casing. Steam wells are frequently located in areas where lost circulation of cement is a problem. The use of lightweight cements (1,400 kg/m3) reduces the loss of cement. Free pipe for the upper 20 to 30% of the well and wellhead growth of up to 0.6 m while steaming a well is not uncommon. A typical thermal cement for a steam well could consist of 50% Class G, 25% spheres and 25% Silica Flour. Foamed thermal cements have been used on a few wells. Wellheads Blowout preventors are bolted to 279 mm, 14 MPa slip-on casing bowls welded onto the surface casing. All production casings, whether primary or thermal, are landed in slips in the surface casing bowls. Primary wellheads are bolted directly to the surface casing bowl and consist of a 279 mm by 179 mm by 14 MPa tubing head with lock down screws, tubing hanger for 73 mm EUE tubing, 179 by 73 mm bonnet, 73 mm BOP, 73 mm Flow tee and 73 mm stuffing box.