N.M. Admin. Code § 19.15.21.13

Current through Register Vol. 36, No. 1, January 14, 2025

Section 19.15.21.13 - TESTS AND TEST PROCEDURES FOR PRORATED POOLS IN NORTHWEST NEW MEXICO

A. Type of tests required for wells completed in prorated gas pools.

(1) Reclassified GPUs. An operator of a well on a GPU that the director has reclassified as non-marginal shall conduct deliverability tests on that well within 90 days of the order reclassifying it, unless there are current tests on file with the division or that order requires a new test. A current test is a test that was conducted during the last test period for that pool or later.

(2) Non-marginal GPUs. Operators shall conduct deliverability tests on wells on non-marginal GPUs every five years. If the division determines that a well's test data and production data warrant more frequent testing of the well, the division may set up special testing schedules for that well.

(3) Scheduling of tests.

(a) Notification of pools to be tested. By September 1 of each year the division's Aztec district office shall notify operators of non-marginal GPUs if their wells will be tested during the following test period.

(b) The operators shall file the results of all deliverability tests required with the Aztec district office within 90 days following the completion of each test. Provided however, that a test completed between December 31 of the test year and March 10 of the following year is due no later than March 31. The division shall not grant an extension of time for filing tests beyond March 31 except after notice and hearing.

(c) The operator's failure to file a test within the above-prescribed times subjects the GPU to the loss of one day's allowable for each day the test is late.

(d) A well scheduled for testing during its test year may have the conditioning period, test flow period and part of the seven-day shut-in period conducted in December of the previous year provided that, if the seven-day shut-in period immediately follows the test flow period, the operator shall measure the seven-day shut-in pressure in January of the test year. The earliest date that a well can be scheduled for a deliverability test is such that the test flow period would end on December 25 of the previous year.

(e) Downhole commingled wells are to be scheduled for tests on dates for the pool of the well's lowermost prorated completion.

(f) In the event the division shuts-in a well for overproduction, the operator may produce the well for a period of time to secure a test after written notification to the division. The operator shall use gas produced during this testing period in determining the well's over/under produced status.

(g) An operator may schedule a well for a deliverability retest upon notification to the Aztec district office at least 10 days before the operator will commence the test. The retest shall be for substantial reason and is subject to the division's approval. The operator shall conduct a retest in conformance with the deliverability test procedures of 19.15.21.13 NMAC. The division may require the retesting of a well by notification to the operator to schedule the retest. The operator shall identify these tests, as filed on form C-122-A, as "RETEST" in the remarks column.

(4) Witnessing of tests. Any or all of the following may witness a deliverability test: a division representative, an offset operator, a representative of the gas transportation facility connected to the well under test or a representative of the gas transportation facility taking gas from an offset operator.

B. Procedure for testing.

(1) The test shall begin by producing a well in the normal operating manner into the pipeline through either the casing or tubing, but not both, for a period of 14 consecutive days. This is known as the conditioning period. The operator shall not change the production valve and choke settings during either the conditioning or flow periods, except during the first 10 days of the conditioning period when maximum production would over-range the meter chart or location production equipment. The first 10 days of the conditioning period shall not have more than 48 hours of cumulative interruptions of flow. The 11th to 14th days, inclusive of the conditioning period, shall have no interruptions of flow. An interruption of flow that occurs as the well's normal operation as stop-cock flow, intermittent flow or well blow down shall not be counted as shut-in time in either the conditioning or flow period.

(2) The operator shall determine daily flowing rate from an average of seven or eight consecutive producing days, following a minimum conditioning period of 14 consecutive days of production. This is known as the flow period.

(3) The operator shall measure instantaneous pressure by a deadweight gauge or other division-approved method during the seven-day or eight-day flow period at the casinghead, tubinghead and orifice meter, and record it along with instantaneous meter-chart static pressure reading.

(4) If a well is producing through a compressor that is located between the wellhead and the meter run, the operator shall report the meter run pressure and the wellhead casing pressure and the wellhead tubing pressure on form C-122-A. Neither the suction pressure nor the discharge pressure of the compressor is considered wellhead pressure. The operator shall enter a note in the remarks portion on form C-122-A stating: "This well produced through a compressor".

(5) When it is necessary to restrict the flow of gas between the wellhead and the orifice meter, the operator shall determine the ratio of the downstream pressure, psi absolute, to the upstream pressure, psi absolute. When this ratio is 0.57 or less, the operator shall consider critical flow conditions to exist across the restriction.

(6) When more than one restriction between the wellhead and the orifice meter causes the pressures to reflect critical flow between the wellhead and the orifice meter, the operator shall measure the pressures across each of these restrictions to determine whether critical flow exists at any restriction. When critical flow does not exist at any restriction, the operator shall report the pressures taken to disprove the critical flow to the division on form C-122-A in item (n) of the form. When critical flow conditions exist, the operator shall measure the instantaneous flowing pressures required in Paragraph (3) of Subsection B of 19.15.21.13 NMAC during the last 48 hours of the seven-day or eight-day flow period.

(7) When critical flow exists between the wellhead and the orifice meter, the operator shall use the measured wellhead flowing pressure of the string through which the well flowed during the test as P_t when calculating the static wellhead working pressure (P_w) using the method established in Paragraph (9) of Subsection B of 19.15.21.13 NMAC

(8) When critical flow does not exist at any restriction, P_t shall be the corrected average static pressure from the meter chart plus friction loss from the wellhead to the orifice meter.

(9) The operator shall calculate the static wellhead working pressure (P_w) of a well under test seven-day or eight-day average static tubing pressure if the well is flowing through the casing; it shall be the calculated seven-day or eight-day average static casing pressure if the well is flowing through the tubing. The operator shall calculate the static wellhead working pressure (P_w) by applying the tables and procedures set out in the Gas Well Testing Manual for Northwest New Mexico available from the division.

(10) To obtain the shut-in pressure of a well under test, the operator shall shut-in the well some time during the current testing season for a period of seven to 14 consecutive days, which have been preceded by a minimum of seven days of uninterrupted production. The operator shall measure the shut-in pressure on the seventh to 14th day of shut-in of the well with a deadweight gauge or other division-approved method. The operator shall measure the seven-day shut-in pressure on both the tubing and the casing when communication exists between the two strings. The operator shall use the higher of such pressures as P_c in the deliverability calculation. When the division determines a shut-in pressure to be abnormally low or the well can not be shut-in due to "HARDSHIP" classification, the operator shall determine the shut-in pressure to be used as P_c by one of the following methods:

(a) a division-designated value;

(b) an average shut-in pressure of all offset wells completed in the same zone; offset wells include the four side and four corner wells, if available; or

(c) a calculated surface pressure based on a calculated bottom hole pressure; the operator shall make the calculations in accordance with the examples in the "Gas Well Testing Manual for Northwest New Mexico".

(11) The operator shall take all wellhead pressures, as well as the flowing meter pressure tests that are to be taken during the seven-day or eight-day deliverability test period in Subsection B of 19.15.21.13 NMAC, with a deadweight gauge or other division-approved method. The operator shall record and maintain the pressure readings and the date and time according to the chart in the operator's records with the test information.

(12) The operator shall change and arrange orifice meter charts to reflect upon a single chart the flow data for the gas from each well for the full seven-day or eight-day deliverability test period; however, the division shall not void a test if the operator satisfactorily explains the necessity for using test volumes through two chart periods. The operator shall make corrections for pressure base, measured flowing temperature, specific gravity and supercompressibility, provided however, if the specific gravity of the gas from a well under test is not available, the operator may assume an estimated specific gravity for the well, based upon that of gas from nearby wells, the specific gravity of which has been actually determined by measurement.

(13) The purchasing company that integrates the flow charts shall determine the average flowing meter pressure for the seven-day or eight-day flow period and the corrected integrated volume and furnish them to the operator or testing agency.

(14) The operator shall calculate the seven-day or eight-day flow period volume from the integrated readings as determined from the flow period orifice meter chart. The operator shall divide volume calculated by the number of testing days on the chart to determine the average daily rate of flow during the flow period. The flow period shall have a minimum of seven and a maximum of eight legibly recorded flowing days to be acceptable for test purposes. The operator shall correct the volume used in this calculation to the division's standard conditions of 15.025 psi absolute pressure base, 60 degrees fahrenheit temperature base and 0.60 specific gravity base.

(15) The operator shall calculate the daily volume of flow, as determined from the flow period chart readings, by applying the basic orifice meter formula or other acceptable industry standard practices.

Q = C' (h_wP_f).⁵

Where:

Q = metered volume of flow MCFD @ 15.025 psi absolute, 60 degrees fahrenheit and 0.60 specific gravity.

C' = the 24-hour basic orifice meter flow factor corrected for flowing temperature, gravity and supercompressibility.

h_w = daily average differential meter pressure from flow period chart.

P_f = daily average flowing meter pressure from flow period chart.

(16) The basic orifice meter flow factors, flowing temperature factor and specific gravity factor shall be determined from the tables in the manual.

(17) The operator shall use the daily flow period average corrected flowing meter pressure, psi gauge, to determine the supercompressibility factor. The operator may obtain supercompressibility tables from the division.

(18) When the operator makes a supercompressibility correction for a gas containing either nitrogen or carbon dioxide in excess of two percent, the operator shall determine the gas' supercompressibility factors.

(19) The division may approve use of tables for calculating rates of flow from integrator readings that do not specifically conform to the division's manual for back-pressure testing of natural gas wells for determining the daily flow period rates of flow upon the operator's showing that the tables are appropriate and necessary.

(20) The operator shall correct the daily average integrated rate of flow for the seven-day or eight-day flow period for meter error by multiplication by a correction factor. The operator shall determine the correction factor by dividing the square root of the deadweight flowing meter pressure, psi absolute, by the square root of the chart flowing meter pressure, psi absolute.

(21) The operator shall calculate the deliverability of gas at the deliverability pressure of a well under test from the test data derived from the required tests using the following deliverability formula:

(P_c² - P_d²)ⁿ

D = Q [(P_c² - P_w²)]

Where:

D = deliverability MCFD at the deliverability pressure, (P_d), (at standard conditions of 15.025 psi absolute, 60 degrees fahrenheit and 0.60 specific gravity).

Q = daily flow rate in MCFD, at wellhead pressure (P_w).

P_c = seven-day shut-in wellhead pressure, psi absolute.

P_d = deliverability pressure, psi absolute, as defined above.

P_w = average static wellhead working pressure, as determined from seven-day or eight-day flow period, psi absolute, and calculated from tables in the manual entitled Pressure Loss Due to Friction Tables for Northwest New Mexico.

n = average pool slope of back pressure curves as follows:

for pictured cliffs and shallower formations, 0.85; and

for formations deeper than pictured cliffs, 0.75.

(Note: Special orders for any specific pool or formation may supersede the above values. Check special pool orders if in doubt.)

(22) The value of the multiplier in the above formula (ratio factor after the application of the pool slope) by which Q is multiplied shall not exceed a limiting value the division determines and announces periodically. The division shall make the determination after a study of the test data of the pool obtained during the previous testing season.

(23) The operator shall test downhole commingled wells in the test year for the pool of the well's lowermost prorated completion and shall use pool slope (n) and the lowermost pool's deliverability pressure. The operator shall use the total flow rate from the downhole commingled well to calculate a value of deliverability. For each prorated gas zone of a downhole commingled well the operator shall file a form C-122-A. Also, in the summary portion of that form all zones shall indicate the same data for line h, P_c, Q, P_w and P_d. The value shown for deliverability (D) is that percentage of the well's total deliverability that is applicable to this zone. The operator shall place a note in the remarks column that indicates the percentage of deliverability to be allocated to this zone of the well.

(24) The division shall consider a test prescribed in 19.15.21 NMAC acceptable if the average flow rate for the final seven-day or eight-day deliverability test is not more than 10 percent in excess of any consecutive seven-day or eight-day average of the preceding two weeks. The division may declare a deliverability test not meeting this requirement and require the operator to re-test the well.

(25) The operator shall make charts relative to deliverability tests or copies of the charts available to the division upon its request.

(26) Operators shall use only testing agencies, whether individuals, companies, pipeline companies or operators, that maintain a log of all tests they have accomplished including all field test data. The operator shall maintain the data collected pursuant to tests Subsection B of 19.15.21.13 NMAC requires for a period of not less than two years plus the current test year.

(27) Forms C-122-A and C-122-B are adopted for use in the northwest New Mexico area in open form subject to modification by the division as experience may indicate desirable or necessary.

(28) The operator shall conduct and report deliverability tests for gas wells in formations in accordance with 19.15.21.13 NMAC. Provided, however, 19.15.21.13 NMAC is subject to a specific modification or change contained in special pool orders the division adopts for a pool after notice and hearing.

C. Informational tests.

(1) One-point back pressure test. The operator may take a one-point back pressure test on newly completed wells before their connection or reconnection to a gas transportation facility. This test is a required official test, but the operator may take the test for informational purposes. When taken, the operator shall take and report this test as prescribed in Paragraph (2) of Subsection C of 19.15.21.13 NMAC.

(2) Test procedure.

(a) The operator shall accomplish this test after a minimum shut-in of seven days. The operator shall measure the shut-in pressure with a deadweight gauge or other division-approved method.

(b) The flow rate shall be that rate in MCFD measured at the end of a three hour test flow period. The flow from the well shall be for three hours through a positive choke, which has a 3/4 inch orifice.

(c) The operator shall install a two-inch nipple that provides a mechanical means of accurately measuring the pressure and temperature of the flowing gas immediately upstream from the positive choke.

(d) The operator shall calculate the absolute open flow using the conventional back pressure formula as shown in the division's manual for back-pressure testing of natural gas wells.

(e) The operator shall report the observed data and flow calculations in duplicate on form C-122.

(f) Non-critical flow shall be considered to exist when the choke pressure is 13 psi gauge or less. When this condition exists the operator shall measure the flow rate with a pitot tube and nipple as specified in the division's manual for back-pressure testing of natural gas wells or in the division's manual of tables and procedure for pitot tests. The operator shall install the pitot test nipple immediately downstream from the 3/4-inch positive choke.

(g) The operator shall test a well completed with two-inch nominal size tubing (1.995-inch internal diameter) or larger through the tubing.

(3) The operator may conduct other tests for informational purposes prior to obtaining a pipeline connection for a newly completed well upon receiving specific approval to conduct the other tests from the Aztec district office. The Aztec district office shall base approval of these tests primarily upon the volume of gas to be vented.

N.M. Admin. Code § 19.15.21.13

19.5.21.13 NMAC - Rp, 19.15.8.606 NMAC, 12/1/08