Appendix 1-A Well Testing

Transcription

1 Appendix 1-A Well Testing

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3 FLOW TESTING PURPOSE Flow testing is used to determine the performance of oil and gas wells and their economic potential. Various tests will be done to determine the amount of hydrocarbons (i.e., oil and gas) and water present for each wellbore drilled into the target formation. Once completed, the testing will also determine the quality of the hydrocarbons and the ease and rate of extraction. Information from all the flow tests will be reviewed and assessed to determine if a field has commercial potential or whether further exploration would be needed to collect more data. The results of the flow testing will also be used as an input to determine the requirements for potential processing facilities, infrastructure (e.g., pipelines), the number and placement of production wells and well sites to optimize resource extraction, and potential areas of future development of the field. TESTING ACTIVITIES Flow testing will start after drilling and completing (using the hydraulic fracturing process) the exploration well. Testing will involve: placing sensors immediately above the production interval in the wellbore to record temperature and pressure during the test installing surface test equipment to measure surface fluid and gas rates, and temperature and pressure during the test opening the well to allow formation fluids and gas to flow through the tubing and up to the surface. Initially, the formation might produce a flow without the aid of pumps to pull liquids to the surface. If necessary, additional tests will be conducted using pumps to produce a flow at various pressures to remove a volume of fluid over a set period, and to observe the effects when the pressure is removed. This will show how the formation responds at a well when removing fluid at different rates over time. analyzing samples of produced fluids (i.e., oil and water ) and gas to determine their composition and quality flaring produced gas separating produced water and oil and storing them in above-ground tanks. The tanks will be emptied periodically and the products taken to a secondary storage site before being transported for sale or disposal. 1

4 FLARING During well testing, gas will be produced along with water and oil that flow through the wellbore and up to the surface. Because this is an exploration program, the amount of produced gas is unknown. Furthermore, because of winter-only operations, ConocoPhillips will conduct flow testing for a relatively short duration (from 60 to 120 days), which would potentially limit the amount of gas produced. Because of these conditions, ConocoPhillips has determined that using a flare stack will be the most economical, efficient and safe method to dispose of any produced natural gas. ALTERNATIVES CONSIDERED FOR HANDLING PRODUCED GAS ConocoPhillips considered five alternatives to handle produced natural gas during well testing: transporting the gas by pipeline converting the gas to compressed natural gas (CNG) venting the gas directly to the atmosphere incinerating the gas flaring the gas The potential volume of produced natural gas used to evaluate the economics of these alternatives is based on: testing ten wells for three, three-month test periods (a total of 270 testing days per well) a maximum gas flow rate per well during initial flow of 123,000 m 3 /d (4.3 MMscf/d), based on a P90 modelling result. For effective testing, well equipment must be sized to handle this maximum rate. an average estimated produced gas flow rate per well under prolonged flow of 28,000 m 3 /d (1 MMscf/d) Therefore, the estimated natural gas to be produced over the course of the Program is: total testing days per well x number of wells tested x average daily flow rate per well 270 x 10 x 28,000 m 3 /d = 75,600,000 m 3 (2,700 MMscf) Based on a market price of $4.50/mscf, the gross sales value of 2,700 MMscf of produced natural gas is about $12.2 million, if this gas were to be produced near to a gathering system. The estimates provided are used to roughly illustrate potential economics. As stated previously, the estimated gas volumes and whether the project progresses to the development stage are highly uncertain. The analysis of the alternatives concluded that flaring and incineration were the only two cost-effective options, with flaring having a technical advantage over incineration because of its ability to effectively handle varying gas flow rates. 2

5 Transporting Gas by Pipeline The two communities closest to EL470 are Tulita and Norman Wells. Neither of these communities is capable of using natural gas for heating. In Norman Wells, homes and businesses have recently converted to diesel heating because of the reduced supply of natural gas from the Norman Wells oil field. In Tulita, homes are heated with wood and diesel. Because the availability of natural gas from testing would be intermittent and short term, it is not reasonable to assume that potential customers in these communities would spend money to convert their homes and businesses to natural gas. Furthermore, there is no existing pipeline to transport the gas to these communities. Therefore, these two communities are not considered as viable markets for sale of natural gas from testing operations. The lack of a pipeline would also be a factor in transporting gas to the next closest potential point of sale, Wrigley, located 350 km to the south. At a cost of about $400,000/inch-mile, the cost to construct a 3-inch line to Wrigley would be about $260 million. In addition to the pipeline construction cost, the cost of a gas gathering system to connect the wells and collect the gas, plus on-site gas compression to allow transmission to the point of sale would need to be included. Based on the estimated produced gas gross sales value and considering the pipeline construction cost only, this option is not economic. In addition, constructing a pipeline would require clearing land to create a pipeline right-of-way that would require crossing sensitive habitats and waterways. To adequately assess the potential effects of this additional infrastructure, this option would require additional environmental and socio-economic assessments, which would add cost and affect the schedule to complete the Program. Converting Gas to Compressed Natural Gas Compressed natural gas (CNG) is often confused with liquefied natural gas (LNG). While both are forms of stored natural gas, the difference is that CNG is stored as a gas at high pressure, whereas LNG is stored at a very low temperature, becoming liquid in the process. Compared to LNG, CNG has a lower cost of production and storage, and a smaller footprint because it does not require an expensive cooling process and cryogenic tanks. To store an equivalent mass of CNG to that of gasoline requires a much larger storage volume and high pressures ranging from 20 to 28 MPa (3,000 to 4,000 psi). As discussed in the pipeline alternative, the nearest potential gas market is Wrigley. Natural gas would be compressed at the well site into high-pressure tank trucks and transported to Wrigley for sale. The cost to purchase equipment and set up and run a CNG operation on every well test is about $220 million. This estimate is based on: compression equipment requirements: o 1,100 hp compressor (50 psi suction pressure, 3,000 psi discharge pressure, 4.3 MMscf/d capacity) o estimated purchase capital per compressor is $2.2 million (1,100 hp x $2,000/hp) o assume six compressors are required to complete 30 well tests o cost to install compressor per well test is $0.5 million o total estimated cost for compression equipment is about $28.2 million (6 compressors x $2.2 million/compressor + 30 tests x $0.5/installation) 3

6 equipment mobilization and demobilization: o total round trip cost for truck transport to Hay River, barge to Norman Wells and truck transport to the well site on EL470 for compressors, piping and other related equipment is $400,000/season on-site operating costs: o crew cost per well test to operate compressors is about $430,000, based on a four-person crew per test x 90 days x $1,200/d o compressor maintenance cost of $55,000 per well test, based on 10% capital cost per year (2.5% maintenance per three month test = 2.5% x $2.2 million) o electrical generator sets rental cost of $60,000 per well test (estimate $20,000/month x 90 days) o diesel fuel cost of $1.7 million (estimate 10,000 L/d x 90 days per well test x $1.90/L) o total operating cost for program is $67.6 million (30 well tests x (430, , , ,710,000) truck transport of CNG to market: o assume truck capacity of 30 m 3. Equivalent produced gas capacity at standard temperature and pressure is 6,100 m 3 ((20,685 kpa/101 kpa) x 30 m 3 ) o number of trucks required to transport the total volume of produced natural gas is 12,400 (75,600,000 m 3 /6.100 m 3 ) o total cost of truck transport of gas is $124 million (at an assumed cost of $10,000/round trip), pending availability of transport o a storage facility and metering would be needed for sale of gas The total cost of the CNG alternative is $220 million. Based on this cost and the potential revenue for the produced natural gas, this option is not economical. In addition, it is unlikely that sufficient trucks with pressurized tanks could be obtained to support a three-month operation each year. Even if CNG were to be considered, flaring gas would still be required 20 to 30% of the time. Other factors influencing a decision on CNG are: 1) Equipment cannot be sized, rented or purchased unless the process conditions are known. A wide range of process conditions are expected. For example, a gas rate of 100 mscf/d would need about 50 hp of compression, whereas a 2 MMscf/d test would require 800 to 1,000 hp of compression. The compressors would either need clean gas to operate, which is not available, or propane (impractical) or diesel (a 1,000-kW generator set uses about 320 L of diesel per hour). 2) In addition to compression, gas processing would be needed to remove heavy hydrocarbons before the gas could be burned as fuel. These hydrocarbons, which could be in the range of 25 to 50 bbl/mmscf, would need to be stored and transported in pressurized containers. 3) All of this equipment would add significantly to the program footprint likely an area 100 m x 100 m with surface piping. Such a setup would be difficult to do with portable equipment and probably has never been done elsewhere. A 1-MW turbine engine is about the size of a pickup truck, a 1-MW reciprocating compressor package would be about 4 to 6 m wide, 9 to 12 m long and weigh 45,400 kg. A gas processing plant and a number of tanks and a flare system for upsets and safety would be required. 4

7 4) It would be difficult to run this type of equipment reliably because of the intermittent nature of well testing. The best compressors run about 95% of the time in steady service. The equipment reliability in this application is likely to be around 70 to 80%. Therefore, flaring would be required 20 to 30% of the time. 5) Substantial construction would be required to build the compressor station and gas plant, which would also require a number of full-time operators. This would add substantially to the cost and risk to personnel (combining two activities that are rarely combined, completions/testing and gas processing, in close proximity to each other). 6) The operation would be complicated, expensive and substantially increase the site footprint. 7) Environmental considerations include compressor noise, additional truck traffic and land clearing to accommodate safe equipment spacing. To adequately assess the potential environmental effects of this additional infrastructure and activity, an additional assessment would be required, which would add cost and affect the program schedule. Venting Gas to the Atmosphere Direct venting of gas to the atmosphere is unsafe and is discouraged by legislation and industry best practice. For these reasons, this alternative was not considered as viable. Incinerating Gas An incinerator burns gas internally within the stack to allow the gas to almost be completely combusted before exiting the stack. To maintain the combustion efficiency as high as possible, the gas must remain in the incinerator stack long enough to be completely combusted. In addition, a specific temperature must be maintained and the gas must be mixed sufficiently with air to maintain combustion. Therefore, incinerators perform best when the gas flow rate is relatively steady and predictable, and combustion can be maintained for long periods. There is a limit to the range of gas flow rate that a potential incinerator used for the Program would be able to handle and still maintain its efficiency. An incinerator would be more expensive to ship to EL470 than a flare stack because of the incinerator s size, especially one sized to handle higher gas rates. An incinerator capable of handling 2 to 3 MMscf/d of gas would be 4 x 4 x 12 m dimension. Multiple incinerators would be required for higher gas flow rates. Incinerators commonly run with forced-draft burners that require diesel-powered generator sets to provide power. During the initial stages of operation, a flare would be required to handle produced gas until the composition of the gas is suitable for combustion in the incinerator. Flaring Gas A flare externalizes combustion outside of the stack. The main factor affecting flare performance (i.e., combustion efficiency) is wind speed at the top of the stack. A flare can handle the fluctuating gas flow rates expected during well testing without affecting its overall combustion efficiency. From a technical perspective, and given the uncertainty of the gas flow rates associated with an exploration program, a flare system was considered to be a suitable alternative. Furthermore, compared with an incinerator, a flare stack is easier to set up, operate and transport to and from the site. A flare system will provide the 5

8 flexibility to safely handle varying gas flow rates and volumes with a minimal difference in combustion efficiency. FLARING AND INCINERATION COMBUSTION EFFICIENCY Incineration is an internal combustion process, whereas flaring is an external combustion process. Flaring and incineration technologies both use heat to convert natural gas to carbon dioxide and water, with similar combustion efficiencies (i.e., 99.76% to 99.81% for flaring and an assumed 100% for incineration). ConocoPhillips conducted multiple studies using screening dispersion modelling to determine if there is a difference in the downwind concentrations of combustion emissions common to incinerators and flares. The results confirmed that both technologies had similar conversion efficiencies and that the downwind emissions concentrations are essentially the same. Further studies were completed to determine the effect of wind speeds on flare stack performance. To demonstrate the effect of higher wind speeds on flare combustion efficiency during a 24-hour period, stack combustion efficiency was estimated for several wind speeds. 25% of the time the wind speed was greater than 15 km/hr 20% of the time the wind speed was greater than 20 km/hr 5% of the time the wind speed was greater than 25 km/hr Table 1.1 details the results of the modelling, including results for wind speeds up to 40 km/hr. Table 1.1 Effects of Varying Wind Speed on Flare Efficiency Wind Speed Efficiency Scenario (km/hr) (%) Default Value % Alternate Values % % % % % % At higher wind speeds, flare combustion efficiency decreases, but would be greater than 99.5% and above the minimum 98% value recommended by the Alberta Energy Regulator s Directive 60, Upstream Petroleum Industry Flaring, Incinerating, and Venting. GREENHOUSE GAS EMISSIONS The 2011 greenhouse gas emissions in Environment Canada s (2012) National Inventory Report are: 702,000 kt/yr for Canada 1,600 kt/yr for the Northwest Territories and Nunavut 6

9 The predicted greenhouse gas emissions from flaring or incinerating produced gas would be less than 0.4% of the 2011 combined greenhouse gas emissions for the Northwest Territories and Nunavut. Nationally, the proposed flaring would represent less than % of the annual greenhouse gas emissions. As such, the predicted greenhouse gas emission levels would be considerably below the annual reporting criteria of the National Pollutant Release Inventory (NPRI) under the Canadian Environmental Protection Act,

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