ensitive Reservoir Reporting Procedures FORM MMS-127,
"Sensitive Reservoir Report” (SRI)
Sensitive reservoir parameters are documented on
Form MMS-127, formerly “Request for Maximum Efficient Rate" (MER). This form has been renamed Form
MMS-127, "Sensitive Reservoir Information Report" (SRI) and revised
to more accurately reflect its purpose (NTL No. 98-23).
The Minerals Management Service (MMS) developed this document to assist you
in preparing Sensitive Reservoir reports, and to make both of our jobs easier.
Please contact us if you have any questions on either the use of this document
or any of our functions. We will endeavor to answer your questions completely or
put you in contact with the person who can. You may copy any portion or all of
this document for your use.
Paperwork Reduction Act of 1995 Statement (PRA). The collection of
information referred to in this document provides guidance on reporting
information requirements in 30 CFR 250, subparts A and K, and various MMS forms.
The Office of Management and Budget (OMB) has approved the information
collection requirements in these regulations and on the referenced forms. The
OMB control numbers are 1010-0114 (subpart A regulations and form MMS-1123),
1010-0041 (subpart K regulations), 1010-0045 (form MMS-124), 1010-0046 (form
MMS-125), 1010-0039 (form MMS-126), and 1010-0018 (form MMS-127). This document
does not impose additional information collection requirements subject to the
PRA.
REPORTING REQUIREMENTS
The 30 CFR 250 Subpart K Regulations provide
for the prevention of waste and conservation of natural resources of the Outer
Continental Shelf and protection of correlative rights therein.
Regulation 30 CFR 250.1102 (a)(1) requires that an
operator submit Form MMS-127 for each producing sensitive reservoir, and
Regulation 30 CFR 250.1101(d) states that all oil
reservoirs with associated-gas-caps be initially classified as sensitive.
Submit the original plus two copies
(three copies if return receipt is required) of Form MMS-127. Mark
one of the copies "Public Information," with confidential Item Nos. 124-168
blanked out. A copy of Form MMS-127 can be
obtained by calling the Reservoir Analysis Unit. It
is also available on the Internet at
http://www.gomr.mms.gov/homepg/mmsforms/frmindx.html, as a Portable Document
File (.pdf) with an overlay or in Rich Text Format (.rtf) for downloading to a
word processor.
ESTABLISHMENT OF INITIAL SRI
Submit Form MMS-127, for each producing sensitive reservoir within 45 days of
discovering that a reservoir is sensitive. Also, submit a reservoir structure
map along with any other appropriate supporting information (i.e., log sections,
well tests, pressure surveys).
If lease operatorship is transferred, the new operator must submit Form
MMS-127 for all sensitive reservoirs (even though they may currently have an
approved SRI). We will consider the new operator's form as an initial submittal
(a reservoir structure map is required).
The effective date of the SRI submittal for a reservoir will be the first day
of the month in which the Reservoir Analysis Unit receives Form MMS-127.
All other oil reservoirs and all gas reservoirs are initially classified as
nonsensitive. In certain cases, MMS will limit individual well rates via
Form MMS-126, "Well Potential Test
Report", to ensure maximization of ultimate recovery.
SUPPORTING DATA
Provide the following with all SRI forms (including the Annual Review):
- Update all data to reflect current reservoir conditions. Therefore, for
all SRI revisions, update items that have changed, including volumetric and
production data. Also, include the date of the current measured pressure (if
required annually) or, if granted a departure, the date the departure was
granted. A reservoir designated oil w/associated-gas cap requires both sets of
parameters (oil and gas) along with all other basic data.
- Submit the most recent reservoir structure map
(original plus one copy) for initial submittals or if the reservoir has been
remapped or renamed. Show on the map the field, operator, wells (with well names
and reservoir penetration points), reservoir name (including fault block
designation), correct scale, all depth contours and hydrocarbon limits (i.e.,
gas/oil contact, lowest known gas, lowest known oil, oil/water contact, etc.).
Report all reservoir penetration points and hydrocarbon limits in subsea depths.
Also note how the hydrocarbon limits were determined (i.e., gas/oil contact as
seen in Well A-1, oil/water contact estimated from bottom of sand plus one sand
thickness).
- Give a brief description of any enhanced recovery operation activity or
plans in the remarks section of Form MMS-127.
- Fill in both the oil and gas reserve parameters in Item Nos. 124-187 for
oil reservoirs with a gas cap. If such a reservoir has a completion that is
producing an associated-gas-cap (by virtue of a well completed in the gas cap,
across the gas/oil contact, or for a well in which gas coning is occurring), you
will need prior approval to produce such a well. Refer to the section below
titled "Special Reporting Circumstances."
- Include a list of all active completions (the number of completions in the
reservoir that are currently open to production; these completions can be
currently producing or shut-in). This list should correspond with Item No. 175.
- Form MMS-126, "Well Potential Test Report” is required with initial Form
MMS-127 submittals. Submit Form MMS-126 to the Rate Control Unit.
REVISION OF SRI
- Submit Form MMS-127 with the appropriate supporting information as
previously noted to propose a revised SRI.
- Review Form MMS-127 at least once a year (12 months from the effective
date of the last submittal) and submit a revised Form MMS-127 with the
appropriate supporting information as previously noted.
- Submit Form MMS-127 with appropriate supporting information to request the
reclassification of a reservoir from sensitive to nonsensitive and/or request
approval for termination.
SPECIAL
REPORTING CIRCUMSTANCES
- Gas Cap Production Requests:
According to 30 CFR 250.1100,
30 CFR 250.1101, and
NTL No. 98-23, MMS assesses
reservoir management scenarios for production of oil reservoirs with associated
gas caps. Customarily, we make this assessment prior to an operator’s beginning
gas cap production operations for two reasons. First, the lessee/operator is
assured that it has approval before committing or expending capital. Second, MMS
is assured that you will follow sound reservoir management practices to maximize
ultimate recovery. MMS traditionally interprets ultimate recovery as "maximum
oil" recovery by conserving reservoir production energy that the gas cap may
provide. We recognize, however, that ultimate recovery may be measured by a
number of standards and we have granted variance from this traditional
interpretation by approving other reservoir production proposals on a
case-by-case basis.
Listed below are the types of data we use to assess gas cap production
proposals. If you did not generate some of the data listed to make your internal
assessment, submit what you did use and a brief explanation of why this was
sufficient to support your operational plans. If you request that MMS return
this information, we will do so upon completion of the study.
- Development Overview (appropriate in body of letter)
- Proposed completion operations
- Brief geologic review
- Listing of all wells that penetrate subject reservoir and status of each well
- Explanation with supporting data, as to why the proposed completion scenario
will enhance ultimate recovery
- Geological Data
- Depth structure maps with annotated penetration points (SS) for all wells in
the reservoir. Include present and original fluid contacts, reservoir
boundaries (i.e., faults, sand pinchouts, etc.) and labeled well locations.
- Oil and gas isopach maps
- Log sections annotated with top and base of reservoir sand, fluid contacts,
and net pay for all existing penetrations.
- Accessory data, if relevant (i.e., cross-section, sidewall core analysis,
petrophysical data)
- Seismic interpretation used to support decision. Include seismic amplitude
maps, attribute maps, and seismic traverses or lines.
- Engineering Data
- Original and remaining in-place and recoverable oil and gas reserve data,
and data and assumptions used in calculating the reserves
- If a material balance study was done on the reservoir, include the reservoir
parameters used along with the results of the material balance.
- Complete reservoir pressure history
- If a reservoir simulation was run, include the reservoir parameters used in
the reservoir simulation, the history matches, and the prediction runs
(including runs with gas cap production and without gas cap production).
- Detailed economic analysis
- Commingling Requests:
Regulation 30 CFR 250.1106 provides for
permitting commingling of production of two or more separate reservoirs within
a common wellbore. If MMS approves commingling (see
NTL No. 99-G19 and
NTL No. 99-G20), and
determines that the combined reservoir is sensitive, submit
WPT Form MMS-126 and
SRI Form MMS-127 for this commingled production. Include all wells completed
in the reservoirs in the active completions portion of SRI Form MMS-127.
Submit the most recent structure map(s) for the combined reservoirs with the
above forms for the commingled reservoir. Provide a single set (average,
weighted average, etc.) of reservoir parameters. Production data Item Nos.
169-187 should be the sum of the production from the commingled reservoirs. If
both gas and oil zones are involved, classify the combined reservoir
oil-with-associated-gas-cap and provide the appropriate reservoir parameters.
Submit SRI Form MMS-127 for each reservoir unit or composite unit, showing all
wells completed in the unit and the operator of each well. Include the most
recent structure map (if the map has changed since the last submittal) along
with the SRI. Designate commingled reservoirs using approved MMS nomenclature.
The reservoir name is in the MMS downhole commingling approval letter.
FORM OVERVIEW
RESERVOIR IDENTIFICATION
1. Original/Correction: Indicate whether the submission is an original
Form MMS-127 or a corrected copy of
a previously submitted request.
8. Field Name: Same as Item No. 8 on Form MMS-124, "Sundry Notices and
Reports on Wells".
50. Reservoir Name: As designated by the lease operator. The reservoir name
will be stored in MMS information systems in no more than twelve numerical
and/or alphabetic characters including blank spaces. NOTE: Do not use the slash
(/) designation in a reservoir name unless the MMS has approved downhole
commingling.
117. Drive Mechanism: water, partial water, gas cap, depletion, solution gas,
or some combination of these (WTR, PAR, GCP, DEP, SLG, COM).
26. Contact Name: Lease operator representative whom MMS should contact
regarding any problems found with the Form MMS-127 submittal. Please type or
print the name of the person to contact regarding problems with the submittal.
11. Operator Name and Address: Enter the legal company name as given by the
lease documents or approved Form MMS-1123,
"Designation of Operator", on file with MMS, and the complete address of the
submitting office.
10. MMS Operator Number: The lease owner designee on
Form MMS-1123 and filed with MMS by the
lease owner of record, or the reservoir unit operator stated in the MMS unit
agreement.
118. Year of Discovery: The year the reservoir was first penetrated by a well
showing paying quantities according to regulation 30 CFR
250.111.
121. Type of Request:
Initial Submittal: Check if this is an initial SRI request.
Revision: Check if this is a miscellaneous change such as renaming of a
reservoir, remapping, adding or changing producing wells, etc.
Annual Review: Check if this is an Annual Review required under
30 CFR 250.1102(a) (6).
Reclassify Reservoir: Check if requesting to reclassify the reservoir.
NOTE: If lease ownership is transferred, the new operator must submit Form
MMS-127 for all reservoirs in the lease involved. We will consider the new form
as an initial SRI and the most recent reservoir structure map and appropriate
supporting information for the reservoir is required.
89. Attachments: Check to indicate the attachments submitted with this
request.
122. Reservoir Type: Check reservoir type under "Operator Req."
Oil: Check for a reservoir that contains hydrocarbons predominantly in a
liquid state (single-phase).
Gas: Check for a reservoir that contains hydrocarbons predominantly in a gaseous
state (single-phase).
Oil w/associated-gas cap: Check for a reservoir that contains hydrocarbons in
both a liquid and a gaseous state (two-phase).
NOTE: 30 CFR 250.1101(d) requires all oil
reservoirs with associated-gas caps initially to be classified as sensitive.
123. Reservoir Classification: Check reservoir classification under "Operator
Req.” To change the classification of a reservoir, submit a formal written
request along with substantiating information to support the classification. In
addition, submit Form MMS-127 with the appropriate classification.
Sensitive: Check if the ultimate recovery of the reservoir may be decreased
by high reservoir production rates. Refer to 30 CFR
250.1101(d).
Nonsensitive: A nonsensitive reservoir is a reservoir in which production rates
do not have an adverse effect on reservoir performance.
VOLUMETRIC DATA
124. Upper Ø Cut-offs:
The upper porosity cut-off is the highest porosity calculated from a well log or
measured from a core sample (Fraction).
125. Lower Ø Cut-offs:
The lowest porosity at which flow will still occur (Fraction).
126. Upper K Cut-offs:
The highest permeability expected from the reservoir (md).
127. Lower K Cut-offs:
The lowest possible permeability from the reservoir (md).
128. G/O Interface: The
maximum depth (expressed in feet subsea) at which free gas can be found in the
reservoir at current conditions.
129. W/O Interface: The
minimum depth (expressed in feet subsea) at which the water front exists in the
reservoir at current conditions.
130. G/W Interface: The
minimum depth (expressed in feet subsea) at which the water front exists in the
reservoir at current conditions.
NOTE: Item Nos. 124-130
may be determined from well logs, estimated (from adjacent reservoirs, etc.), or
assumed. If assumed, indicate so and give method used.
131. Ag
(acres): The current areal extent of the gas cap portion of the reservoir
expressed in acres.
132. Ao
(acres): The areal extent of the original oil zone expressed in acres.
133. Vo
(acre-feet) (Item No. 132 x Item No. 136): The volume of the original
oil-bearing portion of the reservoir.
134. Vg
(acre-feet) (Item No. 131 x Item No. 138): The volume of the current
gas-cap-bearing portion (free gas) of the reservoir.
135.Ho (feet):
The gross thickness of the original oil zone.
136. ho
(feet): The net thickness of the original oil zone.
NOTE: These thicknesses
are found for individual wells from well logs. The average reservoir gross and
net oil thicknesses can then be calculated by:
Ho = (sum of
H)/N or ho = (sum of h)/N where
H = gross thickness (ft) h = net or pay thickness (ft) N = number of producing
completions
137. Hg(feet):
Same as Item No. 135 above except in the current gas zone.
138. hg
(feet): Same as Item No. 136 above except in the current gas zone.
139. Øe
(fraction): The effective porosity is a measure of the interconnected void
space in a reservoir rock. Porosity is the pore volume per unit volume of
formation; it is the fraction of the total volume of a sample that is occupied
by pores or voids.
140. Sw
(fraction): The connate or irreducible water saturation is the water saturation
that is indigenous to a particular reservoir rock. This water saturation will
exist after depletion of the reservoir. (Water saturation is the fraction of
the pore volume that contains formation water.) Connate (irreducible) water
saturation may be determined from electric logs or cores.
141. Sg
(fraction): Gas saturation present in the gas cap.
Sg = 1 - Swg
- Sor
Swg = water saturation present in the gas cap (Item No. 140)
Sor = residual oil saturation
142. So
(fraction): Original oil column saturation present in the oil rim.
So = 1 - Swo
Swo = initial water saturation present in the oil rim (Item No. 140)
143. Boi (Units
are in RB/STB, ex: Boi = 1.327): The initial oil formation volume
factor is the reservoir volume in barrels that one stock tank barrel occupies in
the reservoir. Boi is reported from a PVT analysis of the reservoir
fluid. If not measured, it may be estimated from correlations related to
dissolved gas-oil ratio and temperature or from PVT analysis of the reservoir
fluids of an adjacent reservoir (RB/STB).
144. Bgi (Units
are in cu.ft. /SCF, ex: Bgi = .0025 cu.ft. /SCF): The
initial/current gas formation volume factor is the volume occupied in a gas
phase at reservoir pressure (P) and temperature (T), by a unit volume of gas at
standard pressure and temperature. The following equation is used to calculate
Bgi (cu.ft. /SCF) using standard conditions of 15.025 psi and 60
oF.
Bgi = .02829 ZT / P (cu.ft. / SCF)
Z = Gas deviation factor
at reservoir conditions (estimated from correlations related to pressure and
temperature)
T = Temperature at reservoir conditions (oR = oF + 460)
P = Pressure at reservoir conditions (psia)
NOTE: As the reservoir
commences production, replaced Bgi (the initial gas formation volume
factor) with Bg (the gas formation volume factor at present
conditions).
Volumetric Method for
Calculating Oil or Gas "in place":
Be sure data required for volumetrics (Item Nos. 124-155) calculate to initial
oil in place (Item No. 145) and current gas in place (Item No. 146) and are
updated at every submittal to reflect a current picture of the reservoir. To do
so, use basic data numbers or volumetric formulas listed below in Item Nos.145
and 146.
NOTE: If reserves have
been re-estimated since the initial SRI submittal, enter new reserve figures and
indicate how these reserve figures were arrived at (i.e., decline curve
analyses, material balance, reservoir simulations).
145. N = (7758 x Item No.
133 x Item No. 139 x Item No. 142) / Item No. 143 (Units in STB)
OR
N = 7758 (A) h (Ø) So (1/Boi):
N = Initial oil in place (STB)
A = Area of initial oil zone (AC)
h = Initial net height of oil zone (ft)
Ø = Porosity (Fraction)
So = Initial oil saturation (Fraction)
Boi = Initial oil formation volume factor (RBL/STB)
146. G = (43560 x Item No.
134 x Item No. 139 x Item No. 141) / Item No. 144 (Units in SCF)
OR
G = 43560 (A) h (Ø) Sg (1/Bgi):
G = Current gas in place (SCF)
A = Area of current gas zone (AC)
h = Net height of current gas zone (ft)
Ø = Porosity (Fraction)
Sg = Initial gas saturation (Fraction)
Bgi = Current gas formation volume factor (cu.ft. /SCF)
NOTE: G should reflect
current free gas in place. Example: for initial conditions: G = initial free
gas in place in the gas cap for annual reviews or revisions: G = initial gas
plus evolved unproduced solution gas plus injected gas that was migrated to the
gas cap
147. Kh (millidarcies):
Horizontal permeability is a measure of the ability of a reservoir rock to
transmit fluids in a horizontal direction. Horizontal permeability is directly
measured in the lab using core samples or indirectly by the following methods:
Perm. vs. porosity correlations, capillary pressure correlations, flow and
pressure build-up tests, and from resistivity and porosity logs using empirical
correlations.
148. Kv (millidarcies):
The vertical permeability is a measure of the ability of a reservoir rock to
transmit fluids in a vertical direction. The vertical permeability is obtained
using the same procedures as the horizontal permeability.
149. Average Well Depth (ft.
Subsea) = The sum of (T+B) (ft) /N
T = True vertical depth at
the top of productive pay minus kelly bushing elevation. (The kelly bushing is
Item No. 13 on MMS-331, and found on log heading).
B = True vertical depth at base of productive pay minus kelly bushing elevation.
N = Number of producing completions.
150.
Rio (fraction): The estimated oil
recovery efficiency is the estimated fractional recovery of in-place
hydrocarbons. This recovery efficiency depends, among other factors, on drive
mechanism, structure, and well locations.
51. Rig
(fraction): The estimated gas recovery efficiency is the estimated fractional
recovery of in-place hydrocarbons. This recovery efficiency depends, among other
factors, on drive mechanism, structure, and well locations.
152. RioN (STB):
For oil: RioN = Item No. 152 = N x Item No. 150 (STB)
NOTE: The ultimate
recoverable oil reserve is the product of Item Nos. 145 and 150. In the latter
stages of development, it may be determined from production performance.
153. RigG (MCF):
For gas: RigG = Item No. 153 = G x Item No. 151 (MCF)
NOTE: The ultimate
recoverable gas reserve is the product of Item Nos. 146 and 151. In the latter
stages of development, it may be determined from production performance.
154. Np(2)/N
(Fraction): = Item No. 154 = Item No. 182 divided by N
155. Gp(2)/G
(Fraction): = Item No. 155 = (Item No. 184 divided by G) times 1000
NOTE: Use basic data
formulas above to get depletion of reserves-in-place. This item can exceed 1.0
in oil with associated gas-cap reservoirs since associated gas and condensate
are not included in Item No. 146.
FLUID ANALYSIS DATA
156. API(Degrees): The
API gravity is a measure of the specific gravity of the produced liquid
(specific gravity is the ratio of the density of the stock tank liquid as
compared to the density of water at standard conditions). API(Degrees, API)
=141.5 -131.5 x Specific gravity of fluid at 60 oF
157.
Specific gravity: (Fraction) The ratio of the density of a gas to the density
of air at standard conditions (60 oF and atmospheric pressure). This
can be calculated from a gas analysis or can be estimated.
158. Rsi(SCF/STB):
In the absence of gas liberation tests on a bottomhole sample, the gas-oil
ratio from production (Item No. 178 X 1000 divided by Item No. 176, from initial
SRI submittal only) is used for the initial solution gas-oil ratio.
159. µoi (centipoise,
cp): The initial viscosity for a reservoir liquid is normally reported from a
pressure-volume-temperature (PVT) test. If PVT test was not conducted, this item
is not required.
160. µo (centipoise,
cp): The reservoir oil viscosity at the current reservoir pressure is obtained
in the same manner as the initial oil viscosity.
161. Tavg(oF
at datum depth): The average reservoir temperature is found by averaging the
temperature of wells within the reservoir.
162. Pi (psig):
The lessee must conduct a static bottom-hole pressure survey for each new
reservoir. This survey will be conducted within three months after the date of
first continuous production. The pressure should be referred to a common
reservoir datum depth (Item No. 168).
163. Pi Date:
The date the initial static bottom-hole pressure survey was conducted.
164. Pws(psig):
For each producing reservoir with three or more producing completions, a
correct static bottom-hole pressure must be conducted annually on key wells that
are representative of the entire reservoir in order to establish the average
reservoir pressure.
165. Pws Date:
The date the pressure was recorded.
166. Pb (psig):
The bubble-point pressure (Pb) for an undersaturated oil reservoir is
the pressure at which bubbles of free gas first appear. Pb is
reported from a PVT analysis or estimated from correlations related to pressure,
temperature, API gravity, and specific gravity.
167. Pd (psig):
The dew point pressure (Pd) for a gas reservoir is the pressure at
which liquids begin to condense.
168. Datum Depth:
(ft.
Subsea = ft. TVD - KB elevation)
Reference depth for all bottomhole pressures in the reservoir.
PRODUCTION DATA
169. GOR (SCF/STB) : The
gas-oil ratio for a specified month (include date on form) is the total monthly
gas production from all wells divided by the total monthly oil production from
all wells in the reservoir, multiplied by 1000.
170. GOR Date: The year
and month for which the latest GOR in Item No. 169 was calculated.
171. WOR
(STBW/STBO) :
The water-oil ratio for a specified month (include date on form) is the total
monthly water production for all producing wells divided by the total monthly
oil production from all wells in the reservoir.
172. WOR Date: The year
and month for which the latest WOR in Item No. 171 was calculated.
173. NO. of Injection
Completions: The number of completions that are currently injecting fluids into
the reservoir.
174. NO. of Abandoned
Completions: The number of completions in the reservoir that have been squeezed
and plugged and abandoned per 30 CFR 250.702. (Does not include
shut-in wells.)
175. NO. of Active
Completions: the numbers of completions in the reservoir that are currently
open to production (non-squeezed); these completions can be currently producing
or shut-in. These are the completions that must be shown in the "Active
Completions in Reservoir" list (Item No. 115).
176. Np(1),
178. Gp(1), 180. Wp(1): The cumulative oil, gas, and
water, respectively, produced from the reservoir at the time of last submission
(STBO, MCFG, BBLW). If oil and condensate are produced from the same reservoir,
include the total oil and condensate number here, but list the amount of
produced condensate in the remarks section. Same for gas-well, gas and
associated gas.
177. Np(1)
Date, 179. Gp(1) Date, 181. Wp(1) Date: Dates of
cumulative oil, gas, and water production for last submittal.
182. Np(2),
184. Gp(2), 186. Wp(2): The cumulative oil, gas, and
water, respectively, produced from the reservoir at the present submission (STBO,
MCFG, BBLW).
183. Np(2)
Date, 185. Gp(2) Date, 187. Wp(2) Date: Dates of
cumulative oil, gas, and water production for present submittal. See note for
Item No. 176.
115. ACTIVE COMPLETIONS IN
RESERVOIR
A list of completions in
the reservoir or the reservoir unit producing, injecting, or shut in (including
wells that have not been squeezed). The total number of completions must
coincide with Item No. 175 in the Production Data Section. Designate Reservoir
Unit completions operated by someone else. Obtain the correct lease number, well
number (completion number), and API number from your approved copy of the
Form MMS-124,
"Sundry Notices and Reports on Wells".
Lease Number: See Item
No. 4 on MMS-124
Well Name: See Item No. 3
on MMS-124
API Well Number: See Item
No. 2 on MMS-124
119. Present MER:
Current Maximum
Efficient Rate of Reservoir. This is required only for the Pacific and Alaska
Regions.
120. Requested MER:
Requested Maximum Efficient Rate for Reservoir. This is required only for the
Pacific and Alaska Regions.
THIS SPACE
FOR MMS USE ONLY
Requested MER:
Although the Gulf
of Mexico Region no longer requires an MER, the GOMR region does reserve the
right to set one. The Pacific and Alaska Regions still requires a requested MER
and will notify the operator via Form MMS-127 whether the requested rate has
been accepted or rejected
MMS Authorizing Official:
Signature of MMS authorizing official.
Approved By: Signature of
MMS approving official.
Effective Date: MMS
assigned effective date.
OPERATOR INFORMATION
116. Remarks: Any
pertinent information pertaining to the application as provided by the operator,
such as: well reclassification, inclusion of secondary gas, calculated in-place
figures, reservoir name change, geologic reinterpretation, etc.
27. Telephone Number:
Telephone number of company representative (named in Item No. 26).
32. Contact E-mail
Address: E-mail Address of company representative (named in Item No. 26).
28. Authorizing Official
(Type Name): Typed name of lease operator's representative.
29. Title: Title of
authorizing official.
30. Authorizing
Signature: Signature of lease operator's representative (named in Item No. 28).
31. Date: Date signed by
lease operator representative.
The Minerals Management
Service (MMS) developed this document to assist you in preparing Sensitive
Reservoir reports, and to make both of our jobs easier. If you have any
questions on either the use of this document or any of our functions, please
contact Ms. Holly Karrigan at 504-736-2834 or by email at
holly.karrigan@mms.gov.