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HomeMy WebLinkAbout2021 Oooguruk-Kuparuk Oil Poolenp us opera�i�ng
Annual Reservoir Surveillance Report
Oooguruk-Kuparuk Oil Pool (OKOP)
Oooguruk Field
April 1, 2022
Table of Contents
BJ ECT PAGE
1.0 Progress of the Enhanced Recovery Project................................................................................ 1
2.0 Results and Analysis of Reservoir Pressure Surveys within the Pool ........................................... 3
3.0 Results and Analysis of Production and Injection Log Surveys, Tracer Surveys,
Observation Well Surveys and Any Other Special Monitoring.................................................... 3
4.0 Review of Pool Production Allocation Factors and Issues Over the Year ..................................... 3
5.0 Reservoir Management Summary.............................................................................................. 5
ATTACHMENTS
ATTACHMENT A: OKOP Well Location Map.............................................................................................7
ATTACHMENT B: 2021 OKOP Voidage Balance by Month.......................................................................8
ATTACHMENT C: 2021 OKOP Pressure Report, Form 10-412..................................................................9
ATTACHMENT D: OKOP Reservoir Pressure Map — December, 2021....................................................10
ATTACHMENT E: OKOP Annual Reservoir Properties Report, Form 10-428.........................................11
Eni Petroleum - Alaska Development
1.0 Progress of the Enhanced Recovery Project
The Oooguruk Field (OF) is one of two Eni US Operating Co. Inc. (Eni) offshore -operated fields in
Alaska. Three oil pools, the Torok, Kuparuk, and Nuiqsut, are currently under development within
the OF. The development consists of an offshore man-made gravel island, the Oooguruk Drillsite
(ODS), located just east of the Colville River Delta in Harrison Bay. ODS production is delivered to
the Oooguruk Tie-in Pad (OTP) via a buried subsea flowline bundle and onshore flowlines,
metered, then transferred to Kuparuk River Unit (KRU) facilities, operated by ConocoPhillips
Alaska, Inc. (CPAI), for final processing and transportation to the sales line.
The Oooguruk-Kuparuk Oil Pool (OKOP) development includes eight wells: ODSK-13i, ODSK-14,
ODSN-29 Kuparuk, ODSK-33, ODSK-35Ai, ODSK-38i, ODSN-40i Kuparuk, and ODSK-41. The
locations of the OKOP, the OKOP wells, the current OU, and Oooguruk Kuparuk Participating Area
(OKPA) are shown in Attachment A. Currently three producers, ODSK-14, ODSK-41 and ODSN-29
Kuparuk, and one injector, ODSK-38i, are active. The ODSK-33 well is inactive due to high water
cut, ODSK-13i remains shut-in for long term pressure fall -off monitoring, ODSK-35Ai is shut-in
and secured due to multiple tubing leaks, and the ODSN-40i Kuparuk is shut-in due to limited
injection capacity.
During 2021, OF engineering and operational efforts were focused on optimizing and
debottlenecking existing equipment, including separator control system performance,
proportional fluid sampling maintenance and upgrades to both the daily and monthly production
fluid samplers, and improving measurement system accuracy. Operations included general
maintenance and replacement of critical oil, water, and gas piping and valves. Additional field -
wide maintenance was also performed, including mechanical integrity inspections of piping and
other safety systems. Routine maintenance was performed on the three power generation
turbines and two gas injection compressors at the OTP, with one of the power generation
turbines receiving a complete overhaul replacement. Compressors A and B were inspected to
identify potential design flaws and asset integrity improvements. In addition, cathodic protection
inspections were completed on the sub -sea production flowline from ODS to OTP to ensure
mechanical integrity of the pipelines. Mandatory DOT hydrotesting was successfully performed
on the 2-inch diesel flowline from OTP to ODS. A detailed monitoring plan for injection system
microbes was established with three biocide treatments conducted during 2021.
Minor capital projects included design studies to relocate the ODS and OTP control rooms, with
ODS control room in process to be relocated, enhancing the ODS polar bear camera system,
seawater injection line pig trap upgrades and adding a corrosion coupon to the ODS subsea diesel
flowline. Several corrosion coupons were pulled at OTP and ODS for the monitoring plan. A
conversion from the existing Siemens PCS7 Distributed Control System (DCS) to Emerson DeltaV
has been approved with detailed engineering scheduled for 2022.
Major capital projects included finalizing the commissioning and startup of the Seawater
Injection System (SWIS) booster pump upgrade at ODS. SWIS started up in May 2020 allowing
higher pressure, increased from 2,800 psi to 3,300 psi, and sustained higher seawater injection
Eni Petroleum -Alaska Development Page 1
rates at ODS. The SWIS project was trigged by the conversion of the KRU CPF-3 HAMI line supply
to produced water in 2019. SWIS was implemented to avoid life cycle production and reserve
loss associated with injection of KRU produced water and to improve reliability. Since
implementation, seawater supply has been consistently available at required volumes for
reservoir management. Once fully implemented the ODS booster pump will further increase
injection pressures, where needed and approved, up to 3,700 psi.
The Oooguruk development originally envisioned producing wells would ultimately utilize
electrical submersible pump (ESP) completions in order to maximize drawdown and minimize gas
lift and the associated KRU and hydraulic back -out effects. However, currently all OF producing
wells require gas lift to produce. Gas lift capacity is limited to approximately 20 MMSCFPD. The
high gas lift rate coupled with approximately 4 to 12 MMSCFPD in combined OF formation gas
significantly increases the flowline pressure, reducing overall flowrates, and generates significant
back -out cost at KRU, which is also primarily constrained by gas processing capacity. These
constraints result in backing out KRU fluid production when high total gas oil ratio (TGOR,
includes formation and lift gas) OF fluids enter the system. Because of the hydraulic effects and
KRU back -out all OF wells cannot be produced concurrently using gas lift. In 2021, on average,
twelve of the 22 available producing OF wells were on-line with TGOR ranking typically used to
determine which wells to produce. Consequently, due to non-competitive TGORs, using back-up
gas lift systems associated with failed ESPs and significant water production, ODSK-41 was limited
to 70 days of production and ODSK-41 was not produced during 2021. ODSN-29 Kuparuk
sustained production was considered a priority due to adverse effects (reduced oil rates with
high watercut and high GOR) when shut-in despite its high TGOR ranking; the well accounted for
88% of OKOP production in 2021.
An engineering study was completed and approved to construct a 20 MMSCFD on site Partial Gas
Processing (PGP) at OTP to mitigate gas processing constraints, reduce associated costs from KRU
CPF-3, and unburden the CPF-3 gas treating and compression system. Detailed engineering began
in June 2021 and startup is forecast for late 2023. In addition, an Electrical Power Sharing (EPS)
feasibility study was also completed and approved to interconnect the Oooguruk and Nikaitchuq
power generation systems to allow a more robust and efficient power system sharing between
the two development projects. EPS startup is forecast in 2024.
In 2019 and early 2020 Eni initiated rig repairs, maintenance and material purchases in
preparation for planned OF workover and drilling programs. However, due to low crude oil prices,
the reduced demand for oil, and the logistical interference of the COVID-19 pandemic no rig
workovers nor new drilling were conducted at the OF in 2021. Subsequently, rig mobilization,
recommissioning of the Rig Support Complex (RSC) and workover planning have been reinitiated,
including four OKOP wells. OF rig activity is planned to start in mid-2022. Timing of the OKOP
workovers is dependent on equipment availability and execution of other priority rig
interventions and drilling activities. Currently, the plan is to eventually recomplete both
producing wells, restore integrity of the tubing in the ODSK-35A injection well, and recomplete
the ODSN-06 well in the Kuparuk formation, similar to the ODSN-29 recompletion in 2017.
Eni Petroleum -Alaska Development Page 2
Annual average daily OKOP oil production for 2021 was 555 BOPD. Total oil production during
2021 was 202,615 barrels for a cumulative 10,090,263 barrels since field start-up in 2008. The
2021 annual average producing gas oil ratio (GOR) and watercut were 2,466 SCF/STBO and 71%,
respectively. The December 2021 average GOR was 2,073 SCF/STBO and the watercut was 76%.
Average annual daily water injection for 2021 was 726 BWPD with daily rates ranging from 0 bpd
to 10,846 bpd. Total water injection in 2021 was 264,967 barrels and 15,914,595 barrels since
the start of injection in 2009. Attachment B details the 2021 monthly and cumulative voidage for
the OKOP.
2.0 Results and Analysis of Reservoir Pressure Surveys within the Pool
Three pressure surveys were reported from three OKOP wells; the pressure survey results are
presented in the OKOP Pressure Report, Form 10-412, Attachment C.
The OKOP Reservoir Pressure Map, Attachment D, depicts the estimated OKOP average pressures
for December 2021 including all wells, shut-in and producing. Overall, the pressures in the main
development continue to show pressure equalization due to historical voidage replacement,
excluding the ODSK-41 area, which, despite 80% downtime in 2021, continues to show limited
communication to offset wells. Pressures from the ODSK-13i injection and fall off test continue
to demonstrate the western Ivik block has relatively low transmissibility and is not in hydraulic
communication with the main development area including the ODSN-29 Kuparuk completion to
the east.
The December 2021 OKOP pressure at 6,050 ft. TVDss is estimated at 2,500 psi (refer to
Attachment E, Kuparuk Annual Reservoir Properties Report Form 10-428).
3.0 Results and Analysis of Production and Injection Log Surveys, Tracer
Surveys, Observation Well Surveys and Any Other Special Monitoring
A chemical tracer program was initiated in May 2012 and completed in 2014. Tracers were
injected into ODSK-35Ai and ODSK-38i. Within 20 months of initial injection tracer concentrations
were observed in ODSK-33 and ODSK-14 from ODSK-35Ai. To date, ODSK-38i tracer has only been
seen in minor amounts in ODSK-33. Produced water samples for ODSN-29 Kuparuk have not
shown signs of either tracer. No additional surveillance logging or surveys were conducted in
2021.
4.0 Review of Pool Production Allocation Factors and Issues Over the Year
Production from the Oooguruk-Torok Oil Pool (OTOP), Oooguruk-Kuparuk Oil Pool (OKOP) and
Oooguruk-Nuiqsut Oil Pool (ONOP) is commingled at the surface into a common production line.
Eni Petroleum -Alaska Development Page 3
Allocation between the pools is based on the ratio of total production for a pool to the total
production for the Oooguruk Unit. The pool allocation factors for 2021 are:
ONOP:
91.0%
OKOP:
8.8%
OTOP:
0.2%
Theoretical production for individual wells for all pools is calculated daily. During 2021 wells were
produced with chokes at 100% most of the time due to the capacity of the production line. Daily
theoretical production for a well was calculated using the data from the most current well test
and the amount of time a well was on production for a given day:
MZn2ZteSprodnced
xDailyRate(BOPD) werhesl = TheoreticalDaily Production
1440 Minutes
day
The daily allocation factor for the unit is calculated by dividing the actual total production for the
day by the sum of the theoretical daily production for each individual well. Daily allocated
production is assigned to each well by multiplying its theoretical daily production by the daily
allocation factor.
The average daily allocation factor for 2021 was 0.9281.
Eni Petroleum -Alaska Development Page 4
5.0 Reservoir Management Summary
The AOGCC issued pool rules under Conservation Orders No. 645A, 596 and 597 for the OTOP,
OKOP and the ONOP, respectively. While there is no subsurface commingling, unitized
substances produced from the three oil pools are commingled on the surface.
Area injection orders (AIOs) authorizing the injection of fluids for enhanced oil recovery in the
OTOP, OKOP, and ONOP reservoirs were issued by the AOGCC as AIO No. 37A, 33 and 34,
respectively. Injection commenced into the OKOP in 2009.
The OKOP reservoir management targets maximizing oil production, managing producing gas oil
ratios. (GOR) and maximizing long term reservoir performance and value through enhanced
recovery while minimizing the project risks and maintaining the highest environmental and safety
standards. Flood throughput and reliable water supply are critical to long-term OKOP recovery.
Consequently, Eni implemented SWIS in 2020 and 2021 to avoid injecting KRU produced water,
improve water supply reliability, and increase available injection pressures. SWIS uptime has
been very high, successfully meeting OF reservoir injection targets and increasing supply
pressure. Additionally, once the ODS booster pump is placed in-service, water injection supply
pressures can be boosted from 3,300 psi to 3,700 psi, which will significantly increase injectivity
and flood throughput in certain low injectivity wells. The AOGCC has approved increasing the
pressure limit to 3,700 psi from 2,800 psi for both the ONOP and OKOP; however, the OTOP limit
currently remains at 2,800 psi consistent with Rule 4 of AIO 37A. Typically higher injection
pressures are not needed for Kuparuk reservoir injection; however, one well ODSN-40 with
limited injectivity may benefit.
Because the OKOP development area is a very mature flood, in a dual porosity system, with highly
variable matrix permeability and open fracture networks, voidage replacement has been
purposely reduced to minimize waterflood by-pass while stabilizing the reservoir pressure and
the GOR. As a result, the producing Kuparuk water oil ratio and oil production have remained
stable and ultimate recovery is projected to exceed expectations. However, during the extended
2019-2020 water injection shutdown, the OKOP producing GOR increased from 3,200 SCF/STBO
to 4,800 SCF/STBO. Subsequently, injection and offtake have been managed and the December
2021 GOR has declined to 2,073 SCF/STBO. However, the watercut has climbed to 76%. At the
end of 2021 OKOP cumulative voidage replacement was at 59%, refer to Attachment B.
OKOP 2021 production was primarily associated with the ODSN-29 Kuparuk in the eastern Ivik
fault block. Despite its high TGOR ranking its production uptime was considered a priority due to
adverse effects (reduced oil rates with high watercut and high GOR) when shut-in. Due to the
proximity to the only active injection well, ODSK-38, oil production decline has recently increased
while water rates are also accelerating despite minimizing injection. Kuparuk production from
the ODSN-29 wellbore has shut-in Nuiqsut production since 2017. Consequently, plans are being
implemented to recomplete the ODSN-06 wellbore in the Kuparuk, which will expand the
developed OKOP area to the north and shutting in the ODSN-29 Kuparuk allowing reopening the
Eni Petroleum -Alaska Development Page 5
Nuiqsut. Moving OKOP production more distal to ODSK-38 injection will improve OKOP
performance and ultimate recovery.
The ODSN-06 well was drilled in 2015 to appraise and test the Nuiqsut southern Ivik fault block.
Following the staged hydraulic fracture stimulation of the Nuiqsut lateral in early 2016,
production was initiated on June 2, 2016. Primary production from the Nuiqsut in the well is over
600 MBO, but it is currently non-competitive on gas lift due the high TGOR required to produce
the well and the associated low primary oil rates. Also, the original plan to convert the well to
injection is not planned nor approved, at this time, as the targeted offset producers have not
been approved to drill. The planned completion will allow future access to the Nuiqsut.
However, while drilling to the Nuiqsut in 2015, reservoir data was collected in the Kuparuk
interval demonstrating high mobilities and pressures consistent with the developed area around
the ODSK-38 injection well. Consequently, the ODSN-06 workover is being conducted to isolate
the Nuiqsut formation and initiate production from the Kuparuk formation, similar to the
workover conducted in ODSN-29 in 2017, which has produced over 1.2 MMBO. Nuiqsut and
Kuparuk commingling is not planned nor requested at this time. Additionally, initiating Kuparuk
production more distal from the ODSK-38 injection will improve recovery and allow the ODSN-29
well to produce exclusively from the Nuiqsut, improving recovery from both Pools.
Eni Petroleum -Alaska Development Page 6
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