Part 6. Production

This part applies only to the production of oil and gas.

6.0 Exceptions

The requirements of sections 6.1, 6.4.1, 6.5, 6.12 and 6.12.1 do not apply to operators of private wells.

6.1 Measurement

Before production of oil and gas from a well commences, the operator shall arrange surface equipment and install metering equipment or meter test points on each well so as to permit the:

  1. measurement of the tubing and casing pressure;
  2. measurement of the flow rate; and
  3. sampling of oil, gas and water.

6.1.1 Periodic test measurements

An operator may determine well production volumes based on periodic well test determinations and circumstances that are acceptable to the Ministry.

6.2 Records

The operator of a producing oil or gas well shall keep at an office in Ontario complete and accurate records of the well showing:

  1. the quantities of oil, gas and water produced;
  2. the average separator pressure, if a separator is in use;
  3. full particulars of the disposition of all products of the well; and
  4. where the product is sold, the name of the purchaser and amount realized from the sale.

6.2.1 Group production

The operator may commingle oil, gas and water production from two or more wells prior to measurement where:

  1. production from a pool averages less than 1 m3/d oil per well and 0.3 103m3/d gas per well and all the oil gas interests subject to the commingling have been unitized;
  2. where production recovered at surface originates from multiple deviated, horizontal or lateral wells drilled from the well at surface and all the oil and gas interests affected by the commingling have been unitized, and
  3. production occurs from gas wells located in Lake Erie.

6.3 Conservation

The operator of a well shall use every possible precaution to prevent waste of oil or gas in production operations and in storing or piping oil or gas, and shall not use oil or gas wastefully or allow it to leak or escape from natural reservoirs, wells, tanks, containers, pipes or other works. Operators shall:

  1. prevent the waste of hydrocarbon resources;
  2. prevent the waste of reservoir energy;
  3. maximize the ultimate recovery of oil and gas; and
  4. minimize the flaring or venting of gas where practical.

6.3.1 Conservation methods

Acceptable methods of gas conservation include:

  1. use as fuel gas;
  2. conversion and sale, as usable heat or electrical energy; or
  3. re-injection of the gas into the producing formation to enhance recovery and to maintain reservoir pressure.

Note: A permit to inject under section 11 of the Oil, Gas and Salt Resources Act is required for re-injection of gas into a reservoir.

6.4 Reservoir information

The operator shall obtain sufficient, reliable reservoir information to optimize production and to evaluate conservation options and the impact of production on the reservoir.

6.4.1 Production records

Accurate monthly records of all oil, gas and water production volumes and reservoir pressure and fluids injected shall be made for each well. Where grouped production is allowed, accurate monthly records of the combined oil, gas and water production volumes shall be made for the subject pool or field.

6.5 Meters

For individual well metering, operators shall use positive displacement, turbine meters or tank gauging for fluid measurements and orifice, positive displacement or turbine meters for gas production measurements. Where group production occurs, the operator may use tank gauging for fluid measurement of fluid production.

Note: see section 13.11 for annual production reporting requirements.

6.6 Meter accuracy

Where oil, gas and water production meters are installed, the operator shall ensure:

  1. a meter accuracy of ±2%, and:
  2. that meters are re-calibrated and serviced when necessary, and not less than the period recommended by the manufacturer.

6.7 Reservoir pressures

The operator shall determine the bottom hole reservoir pressure as soon as practical after drilling is complete and communication is established with the reservoir and before significant reservoir production and shall report the measurement to the Ministry on Form 7.
Note: Normally this will be after flowback on stimulation or completion of the well.

6.8 Bottom-hole pressure measurements

The operator shall determine bottom-hole pressure using:

  1. static gradients with bottom hole pressure gauges run to the mid-point of the producing formation after sufficient shut-in time to attain stabilization;
  2. shut-in and build-up tests with bottom hole pressure gauges;
  3. electronic or mechanical recorders in the drill stem test string; or
  4. surface deadweight pressure measurements with or without sonic fluid shots depending on the presence of fluid in the well, to calculate a stabilized bottom hole pressure.

6.9 Reservoir fluid samples

The operator shall:

  1. take one representative pressurized oil and solution gas sample from each new oil pool and conduct fluid recombination and pressure-volume-temperature (PVT) studies; or
  2. where reservoir pressure is low and solution gas production volume is low or a high draw down is necessary for significant fluid production, an oil and solution gas sample shall be collected under atmospheric conditions and accepted industry correlations shall be used to estimate PVT properties.

6.10 Initial Production Testing Period (IPTP) report

The IPTP for exploratory and development wells shall be 120 and 90 days respectively from the well’s TD date and the operator shall prepare a report that includes:

  1. daily production volumes of oil, gas and brine;
  2. an estimate of the well’s potential oil and gas reserves and a production forecast for the well;
  3. plans for gas conservation or alternatives being considered;
  4. reservoir evaluation, reserve estimate, pool boundary; and
  5. the stabilized bottom hole pressure at the beginning and end of the IPTP and the method used to determine the bottom hole pressure.

6.11 Gas flaring

The operator of a well shall install flaring equipment and flare all gas volumes that are not conserved and that are capable of sustaining a flare.

6.11.1 Individual wells

After the IPTP, operators shall restrict flaring to no more than a monthly volume of 45 103m3 or 1.5 103m3/d (53 mcf/d).

6.11.2 Flared gas volume

The volume of gas flared shall be measured or determined as the measured produced gas volume minus the measured volume of gas sold minus any volume utilized as fuel or re-injected into the formation.

6.11.3 Daily production

The operator shall attempt to produce the well evenly throughout the month and adhere to the daily maximum allowed volume (1.5 103m3/d) of flared gas as much as practical.

6.11.4 Pools

Where two or more wells are producing from the same pool, the operator(s) shall restrict flared gas volumes to no more than 180 103m3/month to be shared proportionately between operators on a well count basis. No single well shall flare more than the 45 103m3/month limit.
Note: The Ministry shall have the final judgement on which wells are included in a pool.

6.11.5 Flaring limits

Where an operator can demonstrate that conservation of gas is not feasible, operators may request a departure from flaring limits set out in this Standard. Such requests shall be submitted to the Ministry with the following information:

  1. production forecasts of gas, oil and water from the pool under flare restrictions;
  2. production forecasts of gas, oil and water from the pool with proposed flaring volumes in effect;
  3. bottom hole pressure history;
  4. a review of available gas markets in the area; and
  5. an economic evaluation of gas conservation through sale and/or re-injection or other option(s) that demonstrates conservation is not feasible.

6.12 Gas measurements

The operator of a gas pool located onshore shall:

  1. take an annual shut-in pressure measurement on each well in the pool; or
  2. where well pressures can be shown to be representative of the reservoir pressure, take annual shut-in pressure measurements only on the representative wells; and report the measurements made in (a) or (b) on Form 8; and
  3. where an operator has completed a gas well with an estimated open flow in excess of 28.3 103m3 per day, determine the deliverability of the well according to recognized standards of back-pressure testing and shall report the observed field data to the Ministry and report the results on Form 7.

6.12.1 Shut-in pressure

The annual shut-in pressure measurement shall be:

  1. taken with a dead-weight gauge or other equipment acceptable to the Ministry;
  2. taken after sufficient shut-in time has passed for reservoir stabilization or 24 hours shut-in time whichever is the lesser; and
  3. reported as gauge pressure on Form 8.