2 TS-700-ES_0

N:\Operations\FG&P Operations\13 FG&P Engineering\31 Processes\12 Tie In & Measurement\Specifications\2 TS-700-ES.doc

AltaGas Ltd. Internal Document – Private and Confidential

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Engineering Standard and Specifications Index: TS-700-ES

Subject: Customer Tie-In & Metering Specification Prepared by:

Nyssa Ritzel

Business Segment/ Reporting Unit:

Field Gathering and Processing Date: August 29, 2011

Process Owner: Director Operations & Engineering FG&P Reviewed by:

Brandon Doering

Version: In Service Revision: 2

General

Objective:

• Specify requirements for customer tie-ins to existing and new riser locations • Ensure customer meters used for production accounting or allocations:

o Are equipped with electronic flow measurement equipment o Can provide daily measurement data direct to AltaGas corporate meter hub o Meet regulatory requirements

Application:

1.0 Tie Ins – Applies to new connections to AltaGas Pipelines and Facilities 2.0 Meters - Applies to meters used for production accounting or allocations. 3.0 Construction Requirements - Applies to both sections 1.0 & 2.0 above

Audit & Enforcement: • AltaGas reserves the right to conduct an inspection of the Customers’ meter used for production

accounting or allocations. • Any major deficiencies identified during the inspection must be corrected by the Customer within the

specified time frame. Failure to do so will result in shutting in of the receipt point • AltaGas reserves the right to have an AltaGas owned and operated meter on a customer line

1.0 Tie-Ins

A. Required Documentation

Prior to Tie-In Construction - AltaGas shall approve all of the following documentation

1. Completed Customer Tie-In & Meter Form

2. Surveyed site plan, stamped by a profession engineer

3. Process & Instrumentation diagram (P&ID) of the tie-in, stamped by a profession engineer

4. Isometric piping drawing including material list, stamped by a profession engineer

5. Chemical Injection:

a. Chemical injection must be approved by AltaGas

b. Customer must supply rates and chemical information to ensure compatibility with AltaGas pipeline operating manual.

c. Continuous injection of an approved methanol is allowed in the gas gathering system provided notification and rates are communicated and approved.

d. If H2S is being field treated, it must be identified and an untreated H2S concentration must be provided

6. Representative gas analysis

7. Any post well stimulation contaminants must be identified and a plan to meet contractual composition requirements must be approved by AltaGas

8. Sand Management plan outlining how sand will be prevented from entering AltaGas pipelines and facilities as per gas gathering agreement gas quality specifications.

Prior to Flowing - AltaGas shall complete and approve all of the following documentation

9. AltaGas Construction Tie-In/Meter Checklist, Tie In Section



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1.0 Tie-Ins


10. AltaGas Engineering Tie-In/Meter Checklist, Tie In Section

11. AltaGas Operations Tie-In/Meter Checklist , Tie In Section

1.0 Tie-Ins

B. Tie In Types

Acceptable Tie-in Types

12. Existing AltaGas riser: Minimum additional equipment is shown below in Figure 2:

Figure 2. Typical Tie-in to an Existing AltaGas Riser 13. New riser location: Constructed by Customer with riser ownership and surface lease transferred to

AltaGas upon completion (unless lease acquired by AltaGas). Two possible configurations:

a) Camel back riser: Figure 2 above shows a tie-in to an existing AltaGas camel back riser.

b) Riser with underground vertical bar-T connection: Minimum additional equipment is shown below in Figure 3. Connection shall be oriented vertically.

Figure 3. Underground Customer Tie-in to AltaGas Line



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1.0 Tie-Ins

C. Piping Specifications

General Piping Specifications

14. All piping connections require isolation kits for the integrity of AltaGas’ cathodic protection systems. Isolation kits are to be installed at ownership breaks or nearest practicable connection point. Jumpers are not permitted unless agreed upon in writing. A technical assessment by a qualified individual on the impacts to AltaGas’ cathodic protection system is required

15. The following must also be installed immediately upstream of the ownership break

a. A spectacle blind

b. A check valve

c. High and low sampling connections

d. Local pressure gauge and isolation valve

16. All AltaGas above ground materials must meet low temperature specifications

17. Transition pieces must match existing AltaGas pipeline specifications

18. The Customer must provide a mechanism to de-pressure the pipeline at both ends

19. Materials should meet or exceed AltaGas pipeline requirements

20. The Customer must provide adequate pressure protection on their wells or process equipment set at or lower than AltaGas’ pipeline MOP

21. Requirements for physical barriers and security devices are to be considered in the design and construction of riser sites

22. Pigging facilities for Customer’s line are encouraged but not mandated unless deemed to be necessary due to gas quality issues

23. Automatic ESD valves are required:

e. For all sour applications set to trip at 10% below MOP and at 25% below normal pipeline operating pressure (line failures).

f. For pressure protection.

g. Typically the valve ownership will be transferred to AltaGas once installed to ensure AltaGas Pipeline Operating Manual requirements are maintained



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2.0 Meters


Prior to Construction - AltaGas shall approve all of the following documentation

1. Completed Customer Tie-In & Meter Form, (metering sections).

2. A metering schematic showing the location (or proposed location) of the meter(s) in relation to fuel gas takeoffs and separators must be provided. A sample is indicated in Figure 4 below:

Figure 4. Sample schematic showing meter location

3. Representative gas analysis (GA). Figure 5 below depicts points at which GA may be taken. If GA is taken at point 1, only one GA is required, otherwise GA’s of point 2 and 3 are expected

Figure 5. Gas Analysis sample points

4. Sand Management plan outlining how sand will be prevented from entering AltaGas pipelines and facilities as per gas gathering agreement gas quality specifications.

Prior to Flowing - AltaGas shall complete and approve all of the following documentation

5. AltaGas Construction Tie-In/Meter Checklist, Meter Section

6. AltaGas Engineering Tie-In/Meter Checklist, Meter Section

7. AltaGas Operations Tie-In/Meter Checklist , Meter Section

8. Proof of EFM connectivity to SCADA system and ability to display/access data

9. Confirmation of PGAS connectivity



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2.0 Meters

B. Meter Specifications

Meter Location

10. Meters shall be installed by customers on all connections to an AltaGas pipeline or facility

11. Well site installations will have fuel gas taps taken off upstream of the well measurement point

12. Group measurement points such as compressor or plant sales points will have all fuel gas taken upstream of the group measurement point

13. Gas flow meters shall be downstream of separators (dry)

14. If separated liquids are to be re-injected into the pipeline, the liquid flow must be measured

Meter Equipment

15. Labeled sample point upstream of the orifice meter

16. Sensing lines from differential type meters must be a minimum of 9.525 mm in diameter for meter tubes less than 101.6mm in diameter and 12.5mm in diameter for meter tubes greater than 101.6mm in diameter. Sensing lines must be dedicated to a specific devices, not shared

17. Self draining sensing lines. This means transmitters/sensors/recorders must be located above the primary device. Sensing lines must be sloped to meter by 1”/ft back to the primary device to prevent fluids from entering the sensors/transmitters

18. Transmitter/sensor installations must be located within one meter of the primary device

19. Block valves on sensing lines must be full port valves of the same size as the sensing lines. Manifolds should be five valve manifolds with hard seats

20. Bypass valve must be lockable and car sealed closed during operation

21. Thermowells will be located in accordance with the applicable standards and there shall not be any sort of process connections between the meter and the thermowell

22. Temperature transmitters/RTD probes will be installed with flexible armored cable enabling the RTD to be easily removed from the thermowell for calibration procedures

23. Static pressure shall be taken from the upstream side of the primary element

24. No copper or copper alloys should be used where exposure to sour gas is a potential. Any meters or equipment that could be subjected to sour gas exposure must meet applicable NACE guidelines

25. For orifice meter installations, the latest AGA #3 (or API MPMS 14.3) requirements must be adhered to and meter runs must be designed to operate with a beta range of 0.45 to 0.60

26. Orifice meter runs are preferred to be installed in the vertical position to reduce errors caused by fluid carryover. Horizontal meter runs are acceptable provided that the gas stream is free of liquids

27. Meter installation design should consider the potential for pulsation effects on the installation

28. Fuel gas meters must provide sufficient turndown to handle start up volumes

29. The pressure and temperature connections for positive displacement and turbine meters will be equipped with the appropriate measurement devices and will be located on the upstream side of the meter within 20 pipe diameters of the meter. A sample gas orifice meter configuration is shown in Figure 6



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2.0 Meters


Figure 6. Sample orifice meter configuration

30. Liquid metering must be done using an industry approved turbine or PD meter complete with local totalizer and flow transmitters, complete with strainer/filter upstream of meter

31. Liquid meter installations will include a bypass around the meter to facilitate removal of the meter for inspection repair or replacement. The bypass shall be on the same horizontal plane as the meter

32. Meter installation design will consider the effects of pressure drop across a metering device and in relation to the surrounding piping configuration. Pressure drops in hydrocarbon liquid lines may result in gas breakout or a change of state off the fluid, having a significant impact on the volume determination

33. Where hydrocarbon fluid rates on accounting or allocation meters exceed 3.0m3/day, provisions must be made for inline proving on the meters. Proving taps should be the same size as the flow-line and in should never be any smaller than the meter

34. Liquid dump valves shall be situated downstream of any meter but upstream of the proving taps. The dump valve will be snap acting

35. Liquid meters will be located below the lowest level of the separator to prevent gas breakout in the meter

36. All meters must be protected from the elements

37. Appropriate allowances must be made for upstream piping requirements for all meter types

38. The sensor communicating to EFM on the meters shall operate at a point greater than 10% of the calibrated span under normal operating conditions

39. If orifice meters are used for liquid metering, pressure taps will be located on the horizontal plane and will be mounted on the sides of the meter run. Recorders for orifice metering of liquids will be located below the meter to ensure sensing lines remain liquid filled. Please see Figure 7 below for a sample liquid meter configuration and related components



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2.0 Meters


Figure 7. Sample liquid meter configuration

Meter Data Retrieval and Reporting Requirement

40. Daily measurement data must be made available and reported to AltaGas electronically including at minimum:

a. Daily volume totals

b. For gas: delivery flow, pressure, and temperature

c. For liquid: delivery flow

d. Meter information (factor, orifice, S.G., Z)

e. Time stamp based on contract hour (8am)

f. Gas composition

41. Volumes must be reported in SI units (103m3). All field measurement data, such as line size, orifice size, temperature, pressure, will be reported in SI units.

42. All measurement will be referenced back to standard conditions of 101.325kPa and 15˚C

43. EFM devices will be programmed to publish the following instantaneous data, in metric units of measure, on a minimum interval of hourly:

Item Units

Gas Flow Rate e3m

3/day

Today’s Gas Volume e3m

3

Liquid Flow Rate m3/day

Today’s Liquid Volume m3

Today’s Hours hr

Static Pressure kPa

Diff Pressure kPa

Temp deg. C

Battery Voltage Vdc

Battery Temp deg. C



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2.0 Meters


44. All meters shall be programmed in MST. EFM devices will be programmed to publish the following daily data, in metric units of measure, at the end of the Contract period, which is 8am:

Item Units

Yesterday’s Volume e3m

3

Yesterday’s Time hr

Yesterday’s Average SP kPa

Yesterday’s Average DP kPa

Yesterday’s Average Temperature deg. C

45. For further information on EFM record expectations, such as configuration data, please refer to Measurement Standard 1 – EFM Records

46. AltaGas reserves the right to collect more data than mentioned above

Meter Standards

47. Measurement specifications shall comply with the current version of industry standards, codes and regulations as listed below. In addition to these standards, all installations must comply with appropriate engineering standards including ANSI, ASME, and NACE. The following shall also be used as reference for detail with respect to the installation and operation of measurement devices.

48. American Gas Association

a. Report No. 3, Orifice Metering of Natural Gas Part 1: General Equations and Uncertainty Guidelines

b. Report No. 3, Orifice Metering of Natural Gas Part 2: Specification and Installation Requirements

c. Report No. 3, Orifice Metering of Natural Gas, Part 3: Natural Gas Applications d. Report No. 7, Measurement of Gas by Turbine Meters e. Report No. 8, Compressibility and Supercompresssibility for Natural Gas and other

Hydrocarbon Gases f. Report No. 9, Measurement of Gas by Multipath Ultrasonic Meters g. Report No. 11 Measurement of Gas by Coriolis Meter

49. American Petroleum Institute

50. Manual of Petroleum Measurement Standards

a. Chapter 2 – Tank Calibrations b. Chapter 5 – Metering c. Chapter 6 – Metering Assemblies d. Chapter 7 - Temperature Determination e. Chapter 14 - Natural Gas Fluids Measurement f. Chapter 16 – Measurement of Hydrocarbon Fluids by Weight or Mass g. Chapter 18 – Custody Transfer h. Chapter 21 – Flow Measurement using Electronic Metering Systems

51. American National Standards Institute

a. B109.2 Diaphragm Type Gas Displacement Meters i. B109.3 Rotary Type Gas Displacement Meters

52. Federal and Provincial Regulations

a. Alberta i. Oil and Gas Conservation Act and Regulations ii. ERCB Enhanced Production Audit Handbook iii. ERCB Directive 04- Determining Water Production at Gas Wells iv. ERCB Directive 17- Measurement Requirements for Upstream Oil and Gas v. ERCB Directive 46 Production Audit Handbook vi. ERCB Directive 60 Upstream Petroleum Industry Flaring Guide

b. British Columbia vii. Petroleum and Natural Gas Act viii. Drilling and Production Regulations Part 8



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2.0 Meters


c. Saskatchewan ix. Oil and Gas Conservation Regulations, Part 79 & Part 80

d. Yukon and Northwest Territories x. Canada Oil and Gas Operations Act xi. Canada Oil and Gas Operations Regulations

Meter Accuracy

53. The standards of accuracy of any metered volume shall be monitored and maintained within allowable limits. The standards of accuracy used by AltaGas shall take into account the limitations of measuring devices, operating procedures and human error. In Alberta, in accordance with the current version of Directive 17, if royalty, equity or reservoir engineering needs are required, the maximum uncertainty of any recorded monthly volume and single point of measurement shall be:

Daily Volume (m3) Uncertainty of Monthly

Volume Uncertainty of Single Point

of Measurement

Delivered (Sales Gas) N/A 2% Plant Inlet or Total Battery Gas 5% 3%

Fuel Gas > 500 5% 3% Fuel Gas < 500 20% 3%

Flare Gas 20% 3% Acid Gas N/A 3%

Well Gas > 16.9 103 5% 3% Well Gas < 16.9 103 10% 3%

Well Gas (proration battery) 15% 3% Liquid meters >2 N/A 0.25%

54. In other jurisdictions, maximum uncertainties will comply with the regulatory requirements of the jurisdiction. Wherever maximum allowable uncertainties are defined, such as a legally binding contract, the contract will supersede these stated values. In the absence of any documented maximum uncertainties, those noted in this table shall be used.

55. The determination of combined uncertainty of any single point of measurement shall be done in accordance with the most current version of American Petroleum Institute (API) Manual of Petroleum Measurement Standards, Chapter 13: Statistical Aspects of Measuring and Sampling using the “sum root square” method.

Example: Gas meter uncertainty = 1.0% Meter Proving uncertainty = 0.5% Chart Recorder uncertainty = 1.0% Chart Integration uncertainty = 0.25%

Combined Uncertainty = √ (1.0) 2 + (0.5) 2 + (2.0) 2 + (0.25)2 = 1.52%

3.0 Construction Expectations

Construction Expectations

1. If using AltaGas’ road, an Access Agreement must be completed with AltaGas

2. All Customer representatives and contractors shall participate in a safety indoctrination prior to accessing any AltaGas sites or facilities

3. All Customer representatives and contractors shall have a daily permit and all necessary regulatory permits prior to conducting any work on AltaGas sites. Notification must be given 72 hours in advance of any construction commencement. Work on AltaGas lease or R.O.W. will be carried out or directly supervised by AltaGas representatives



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2.0 Meters


4. During construction, Customer shall give access to AltaGas representatives for inspection and approval of facilities installation

5. All wells shall be cleaned of any drilling and completion fluids prior to flowing into the gas gathering system. AltaGas reserves the right to verify analyses of flow samples prior to accepting gas from the Customer

6. Once construction is completed, the Customer must also transfer the caveat and assign the surface lease over to AltaGas, if they are tying into a riser not already owned by AltaGas

7. Customer is responsible for all costs associated with tying in, including inspection

Reference Documents Name of Document Where located Uses

Engineering Tie In & Meter Checklist OS&P Process Files Engineering Review & Approval Construction Tie In & Meter Checklist OS&P Process Files Construction Review & Approval Operations Tie In & Meter Checklist OS&P Process Files Engineering Review & Approval

Revision History Revision Date Revision Comment

1 February 10, 2011 Approved 2 August 29, 2011 Added Sand Management Plan requirement