Instructions-BOEM-0127 v1

Instructions for Completing
Form BOEM-0127
Sensitive Reservoir Information (SRI) Report

To properly complete Form BOEM-0127, follow the instructions below. Please contact the BOEM
Regional Office listed at the end of this document if you need assistance or have any questions about
how to complete or submit Form BOEM-0127. You may copy any portion or this entire document for
your use.

Reporting Requirements
Regulation 30 CFR 550.1155 requires that an operator submit Form BOEM-0127 for each producing
sensitive reservoir, and regulation 30 CFR 550.1154 states that all oil reservoirs with associated
gas caps be initially classified as sensitive. Submit the original plus two copies of Form BOEM-0127.
Mark one of the copies “Public Information,” with confidential Item Nos. 124-168 blanked out. A copy of
Form BOEM-0127 is available on the Internet at www.boem.gov, as a Portable Document File (.pdf)
with an overlay or in Rich Text Format (.rtf) for downloading to a word processor.

Additional Reporting Requirements
In accordance with 30 CFR 550.1166(c), additional reporting is required for developments in the Alaska
OCS Region. Each time you are required to submit Form BOEM–0127 pursuant to 30 CFR 550.1155,
you must request an MER for each producing sensitive reservoir in the Alaska OCS Region, unless
otherwise instructed by the BOEM Alaska Regional Supervisor.

Establishment of Initial SRI
Submit Form BOEM-0127 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 BOEM-0127 for all sensitive
reservoirs (even though they may currently have an approved SRI under the previous operator). 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 each
Region receives Form BOEM-0127.

1

Supporting Data
Provide the following with all SRI forms (including the Annual Review):
1. 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.
2. 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 know 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).
3. Give a brief description of any enhanced recovery operation activity or plans in the remarks
section of Form BOEM-0127.
4. 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 from the appropriate Bureau of Safety
and Environmental Enforcement (BSEE) regional office to produce such a well (30 CFR
250.1157).
5. 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.

Revision of SRI
1. Submit Form BOEM-0127 with the appropriate supporting information as previously noted to
propose a revised SRI.
2. Review Form BOEM-0127 at least once a year (12 months from the effective date of the
last submittal) and submit a revised Form BOEM-0127 with the appropriate supporting
information as previously noted.
3. Submit Form BOEM-0127 with appropriate supporting information to request the
reclassification of a reservoir from sensitive to nonsensitive.

2

FORM OVERVIEW
Reservoir Identification
Box 1. Original/Correction: Indicate whether the submission is an original Form BOEM-0127 or
corrected copy of a previously submitted request.
Box 8. Field Name: Same as Item No. 8 on Form BSEE-0126, “Well Potential Test Report (WPT)”.
Box 50. Reservoir Name: As designated by the lease operator. The reservoir name will be stored
in BSEE/BOEM 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
BSEE has approved downhole commingling.
Box 117. Drive Mechanism: water, partial water, gas cap, depletion, solution gas, or some
combination of these (WTR, PAR, GCP, DEP, SLG, COM).
Box 26. Contact Name: Lease operator representative whom BOEM should contact regarding any
problems found with the Form BOEM-0127 submittal. Please type or print the name of the person to
contact regarding problems with the submittal.
Box 11. Operator Name and Address: Enter the legal company name as given by the lease
documents or approved Form BOEM-1123, “Designation of Operator,” and the complete address of
the submitting office.
Box 10. BOEM Operator Number: The lease owner designee on Form BOEM-1123 and filed with
BSEE/BOEM by the lease owner of record, or the reservoir unit operator stated in the BSEE unit
agreement.
Box 118. Year of Discovery: The year the reservoir was first penetrated by a well showing paying
quantities.
Box 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 550.1155(b).
Reclassify Reservoir: Check if requesting to reclassify the reservoir.

NOTE: If lease ownership is transferred, the new operator must submit Form BOEM-0127 for all

3

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.
Box 89. Attachments: Check to indicate the attachments submitted with this request.
Box 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 (singlephase).
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 550.1154(a)(1) requires all oil reservoirs with associated gas caps initially to be
classified as sensitive.
Box 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 BOEM-0127 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 550.1154.

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.

4

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 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

5

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 B gi
(cu.ft./SCF) using standard conditions of 15.025 psi and 60 ˚F.
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 ( ˚R = ˚F + 460)
P = Pressure at reservoir conditions (psia)
NOTE: As the reservoir commences production, replace Bgi (the initial gas formation volume factor)
with Bg (the gas formation volume factor at present conditions).
Volumetric Method for Calculating Oil or Gas “inplace”: 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 (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)

6

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. 9 on Form BSEE-0133, Well Activity Report, and also found on log headings).
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.
151. Rig (fraction): The estimated gas recovery efficiency is the estimated fractional recovery of inplace 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 Items 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.

7

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 ˚F.
157. Specific gravity (fraction): The ratio of the density of a gas to the density of air at standard
conditions (60 ˚F 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 (˚F 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 current
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.

8

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 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 bottom-hole 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 (does not include shut-in wells).
175. No. of Active Completions: The number 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.

9

182. Np(2); 184. Gp(2); 186. Wp(2): The cumulative oil, gas, and water, respectively, produced for
present submittal. See explanation for Item No. 176.
183. Np(2) Date; 185. Gp(2) Date; 187. Wp(2) Date: Dates of cumulative oil, gas, and water
production for present submittal.
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 BSEE-0124, “Application for Permit to
Modify (APM).”
Lease Number: See Item No. 10 on Form BSEE-0124
Well Name: See Item No. 1 on Form BSEE-0124
API Well Number: See Item No. 5 on Form BSEE-0124
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 BOEM Use Only
Requested MER: Although the Gulf of Mexico Region (GOMR) no longer requires a Maximum Efficient
Rate, the GOMR region does reserve the right to set one. The Pacific and Alaska Regions still require
a requested MER and will notify the operator via Form BOEM-0127 whether the requested rate has
been accepted or rejected.
BOEM Authorizing Official: Signature of BOEM authorizing official.
Approved By: Signature of BOEM approving official.
Effective Date: BOEM 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) who
may be contacted for further information.

10

28. Authorizing Official (Type or Print 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’s representative.

BOEM Regional Program Office Contacts for Completing Form BOEM-0127
BOEM Alaska OCS Region
Attention: Regional Supervisor
Office of Resource Evaluation
3801 Centerpoint Drive, Suite 500
Anchorage, AK 99503–5823
BOEM Gulf of Mexico OCS Region
Attention: Regional Supervisor
Office of Resource Evaluation
1201 Elmwood Park Boulevard
New Orleans, LA 70123–2394
Mail Stop GM 773E
BOEM Pacific OCS Region
Attention: Regional Supervisor
Office of Strategic Resources
770 Paseo Camarillo, 2nd Floor
Camarillo, CA 93010-6095

11