first article of a three-part series introduces the basis and results of 30-year
lifecycle operation simulations performed to
compare a subsea (wet tree) hub and spoke scheme to a dry tree phased approach
using Frontier’s concepts to develop
major discoveries in the ultra-deep high-pressure Gulf of Mexico.
WHITE, ROY SHILLING
and PAUL HYATT, Frontier Deepwater, and WILLIAM BRENDLING,
previous World Oil articles (February 2020, April / June 2021)
introduced the significant savings and value created by adopting Frontier’s semisubmersible
dry tree production system, with its patented movable wellbay (FrPS) and using
a phased development approach rather than risky, expensive, subsea development
schemes extrapolated from the industry’s Miocene experience. Frontier presented assessments using public
domain information and data from BSEE’s Gulf of Mexico database to clarify how,
and why, the industry’s efforts after 20 years of appraisal have failed
consideration of growing global concern about the actual and potentially
harmful impact of offshore oil and gas operations, this series augments the
body of evidence arguing for use of the permanently moored dry tree FrPS by
presenting results of realistic event domain analyses of operations at a 10-well
development over a 30-year project life. While it is widely known that drilling
and completing wells with subsea BOPs involves much higher risk for loss of
well control, readers will now clearly see the serious difference between the
inherent pollution from DP units (MODUs and service vessels) supporting subsea
developments versus fields with dry tree wells on permanently moored platforms
that could have their power supplied from shore or nearby renewable energy hubs.
the full study effort, Frontier assessed and compared the resource and
operating requirements to appraise, develop and maintain a 10-well Lower
Tertiary development in notionally more than a 4,000-ft water depth. This article focuses on field development and
operation, wherein the biggest and most polluting tools in the exploitation of
the discoveries in the high-pressure Wilcox play are the dynamically positioned
mobile offshore drilling units (DP MODUs). There are additional major offshore
assets regularly involved in the operations of MODUs, subsea wells, and subsea
systems that also depend on DP systems to perform their duties.
study generally ignores these service vessels, even though a field development
option with dry trees supported on a permanently moored floating drilling/production
platform will require considerably less support from these field servicing
vessels than competing subsea system options.
models. An idealized field model was adopted for a study
aimed at comparing and contrasting two distinctly different field development
concepts for a typically large, complex, HPHT Lower Tertiary reservoir in
ultra-deep waters of the Gulf of Mexico. The principal parameters adopted for
this study are:
representative well interventions are modelled. It is assumed that the same
interventions are required, at the same frequencies, for both cases studied (i.e.,
same reliability). However, the tasks required to perform the interventions
differ between the two scenarios.
Occurrence of an intervention request will not
interrupt any ongoing field development operation requiring the same resource
but has priority over starting a new field development operation (drilling,
completion or sidetracking). Tubing clean-out and acid stimulation requests,
which halt production, take precedence over production logging.
tree development model. The simulation begins with start of
drilling the first development well. The development program for the field,
using Frontier’s dry tree (FrPS) technology, is modelled as follows. While the
first of two FrPS units is being constructed, the first two development wells
are drilled to target depth with production casing cemented by using a DP MODU
from the 15 -ksi “fleet”. Simulation time starts when this DP MODU begins work
at drill center #1 of the field. The 15-ksi MODU subsequently pre-drills the
three remaining wells through cementing a 14-in. protective casing string for
the first drill center and temporarily abandons them.
Once the MODU has
completed the above drilling, the installation of the first FrPS unit begins.
Installation and commissioning of the facility is assumed
to take one year. When installed, the first FrPS (FrPS#1) completes the first
two wells. Production begins as soon as the first well is completed (and
cleaned up). Once production has started, any required interventions on
producing wells are performed before beginning work on a new well.
Providing it is not occupied by
interventions, FrPS#1 then proceeds to drill out and complete the remaining
three wells in drill center #1. Production data gathered from the first two
completions can assist the operator in selecting final bottomhole locations for
these wells (directional drilling). It is assumed that the operator acquires
sufficient dynamic reservoir performance information from the first three wells
to sanction phase two. As soon as FrPS#1 has completed well 4, a 15-ksi MODU starts work on drill center #2. This “fleet” MODU is assumed to be
available immediately (mobilization pre-planned). The MODU drills wells 6 and 7
to target depth, and pre-drills the 14-in. casing section for wells 8 to 10 at
drill center #2.
Once FrPS#1 has completed all five wells
at the first drill center, it performs interventions on these wells as required
(when available). Once the “fleet” 15-ksi MODU completes pre-drilling tasks for
drill center #2, installation of FrPS#2 begins (with one-year duration). Once
installed, FrPS#2 begins completing wells 6 and 7, then drilling and completing
wells 8 to 10 (pending interventions). A well is scheduled for sidetracking and
recompletion the first time its production rate drops below 3,000 bopd.
The FrPS rig for the well begins side-tracking as soon as it is available.
of the drilling, completion and intervention operations performed by the 15-ksi
MODU and the FrPS rigs are described as a sequence of tasks. The following is
defined for each task:
wells with hub platform and 20-ksi DP MODU (WET case). For comparison with the FrPS development program, a WET / subsea development is modelled as follows. The simulation starts with a 15-ksi MODU pre-drilling the first three wells to target depth at drill center #1. For the WET case, a six-month evaluation period after each of the first two wells (#1 and #2) is assumed to give the operator time to assess the geological results to do a better job in selecting the bottomhole location for the next well.
Still, the bottomhole location for the first three subsea wells is being selected without the benefit of dynamic production data. As a result, actual production data is only available when selecting two of the bottomhole locations of the five wells at drill center #1, compared to three for the dry tree scenario. To select the bottomhole location of the third well using reservoir performance data, the well would need to be delayed until after the first two wells are completed, produced and evaluated for some time.
Once the first three wells have been
pre-drilled to target depth, the production facilities (hub FPS and subsea/SURF
infrastructure) are installed. This is assumed to take 15 months, including delivery
of subsea trees, manifolds, jumpers, flowlines and controls. Once the
production facilities have been installed, completion commences. The remainder
of development is performed by a 20-ksi MODU. This is assumed to be available
immediately following the installation of the production facility (pre-planned)
and dedicated by the operator to support field development.
On mobilization, the 20-ksi MODU completes
and connects flowlines for the first three wells. It then drills, completes and
connects wells 4 and 5 (subject to availability per intervention duties). As
soon as the 20-ksi MODU has completed all the well development and any pending
intervention requests at the first drill center, it moves to drill center #2 and
begins to develop wells 6 to 10. While developing the second drill center, any pending
intervention requests at either drill center must be tackled before starting on
a new well.
The 20-ksi MODU is assumed to be too
expensive to leave idle, so when it is not needed for drilling, completion or
intervention, it is immediately demobilized from the field and assumed to be
deployed elsewhere to work for the operator. Once the 20-ksi MODU has been demobilized,
any new intervention requests will call for remobilization to the field. A
rectangular distribution of between 30 and 180 days is assumed for the 20-ksi MODU
to return. Once remobilized, the 20-ksi MODU must perform all requested
interventions and sidetracks before leaving again.
development simulation. Simulation models of the dry and wet cases
described above were constructed, using BMT’s Simulated Long term
Offshore Oil Production software, SLOOP. These models were
used to produce 240 realizations of the 30-year project life for each of the
developments. Long-duration time series
of the environmental conditions (hurricane warnings, wind, waves, and loop
currents) for a representative location in the Gulf of Mexico were used.
Different realizations used different year-spans from these time series.
each model, there were 20 realizations starting in each different month of the
year. This averaged the effects of the timing of seasonal influences (such as
hurricanes) relative to the development schedule. Each realization used a different random
number seed, so that intervals between intervention requests and the task
working durations had different values appropriate to their random
distributions. From each realization, detailed data on the performance of the
field development was collected, including:
data are processed to give statistics for the performance of the modelled field
development. The following are some of the key results to provide an overview
of the comparison. Part 2 of this study will provide more in-depth results and
discussion to provide additional context.
1 shows the mean of the monthly average
production rate. For the FrPS case, there are four distinct peaks in production
rate, corresponding to completing all wells at each drill center and, later,
sidetrack/recompletion of the wells. For the subsea case, there are no such
distinct peaks. Peak production is much lower and occurs much later. It remains
suppressed, due to the inability of the single 20K MODU to keep up with the
drilling, completion and intervention requests.
The main reasons for this are:
SLOOP description. SLOOP was developed to model and
evaluate oil and gas operations in harsh environments, such as the North Sea. BMT’s
SLOOP simulation tool has been used in support of strategic operations and
economic planning by leaders in the oil and gas industry for more than 25
of SLOOP enable the simulation of complex field development and operating
systems accounting for:
realistic representation of the environmental conditions is critical. For the
Gulf of Mexico, the following data are typically used:
warnings: Making an operation “hurricane-safe” and, if
necessary, evacuating a platform may require several days. Therefore,
interruptions to operations are triggered by advanced warnings of possible
hurricanes. Warnings are more frequent than occurrences of actual hurricane
conditions at the site. Statistical techniques are used to represent hurricane
warnings, based upon historical tracks data.
and wave data: A long-duration hindcast (100 years)
provides correlated time histories of wind speed and wave height. Since
hurricane evacuations are modelled separately, the extreme conditions due to
hurricanes are removed from the time series and replaced by data from the same
season in other years.
current eddies: Historical data on loop eddy currents
are used to derive statistics of eddy events. Longer-duration time series are
then derived, based upon these statistics.
development and operational performance is simulated through
drilling/completions, installations and field/well systems maintenance
operations, which are described as sequences of tasks. Each task has:
of field production in SLOOP is influenced by:
export by either shuttle tanker or pipeline may be modelled. SLOOP may also be
used to model the receiving end, including environment limits, berth
availability, and storage capacity.
evaluate competing options, SLOOP is used to generate multiple realizations
(time histories) of the performance of each scenario. Each realization uses
different years of environmental data and different occurrences of random
events. Data are collected on the performance of each realization, and, from
these, performance statistics are derived.
simulations have revealed Frontier’s DRY Tree field development plan (using two
FrPS platforms) is expected to recover approximately 31% more of the reserves
in the first 20 years of production from the modeled reservoir (yielding
>$10 billion more revenue at $100/bbl), as compared to the analogous WET
tree subsea/hub scheme due to:
Frontier’s FrPS DRY tree development is generating at least $10 billion
more revenue, the WET/subsea tree scheme is spending more than $10
billion on operations. Fuel costs are in addition, and the DP MODU + hub is
consuming almost 9,000 gals more per day than the two FrPS units, combined. So,
assuming $4/gal, fuel adds approximately $324 million in costs with 1,800,000 lbs
of additional CO2 emissions.
study works highlighted billions in capex savings with Frontier’s DRY tree
concepts (see World Oil 2020 and 2021 articles). Even if the initial capex
for the WET tree field development was the same as the DRY tree concept, the
ENPV of the DRY tree concept would clearly be much higher than that of the WET
tree concept. There are key drivers of the DRY tree concept’s obvious ENPV
advantage. Significantly shorter drilling and completion times allow the DRY
tree FrPS to reach an earlier and much higher peak field production rate. Once
on production, the WET tree wells experience many more delays in servicing and
many more days of down time than the wells in the DRY Tree case, due to more
complex operating requirements and sensitivity to onerous metocean conditions. For
the WET tree wells, sidetracking / recompleting to bring on additional reserves
is delayed by many years.
study has assumed that each well may only be sidetracked and recompleted once.
However, rig utilization statistics indicate that the two FrPS units have spare
availability to perform additional recompletions, if the geology justifies
them. This means that declines in production rate could be minimized by
replacing poorly performing wells in the DRY case or even that new reserves may
be added to the field.
2 of this study will present more detailed simulation results, comparing the
two concepts, adding additional context, and understanding of the models and
Frontier’s Executive V.P. and co-founder, is a naval architect (University of
Michigan, 1975) with a masters degree in mechanical engineering (University of
Houston, 1983). He is a past chairman of SNAME Texas. Mr. White worked for IOCs
for over 20 years as a project manager and deepwater technology leader. Since
2000, he has worked primarily on deepwater and natural gas industry projects
and technology development. He has led several large joint industry projects,
as well as the API global task forces in writing the FPS and riser design RPs. Mr.
White also co-chaired creation of the first probabilistic riser design code. He
holds multiple U.S. and international patents.
SHILLING, Frontier’s President and co-founder, is an Ocean
Engineer with a Mechanical BE (Vanderbilt, 1976) and Ocean Engineering MS
(Texas A&M University, 1978). He has over 40 years of deepwater development
experience, including 37 years with BP. Throughout his career, Mr. Shilling has
worked as a project manager and deepwater technology leader, including Project
20K and BP’s Lower Tertiary projects, like Kaskida and Tiber. During Macondo,
he led BP’s containment effort by patenting the free-standing riser system,
installed in 51 days and successfully operated with the Helix Producer 1. Mr.
Shilling holds multiple U.S. and international patents, and has authored
several technical publications.
is Frontier’s V.P., drilling and completions, and managing director of TD
Solutions. He is a specialist in all phases of well design and operations, from
exploration to full field development. He has 41 years of global experience, including
technical and project management roles in offshore, deep water, arctic
operations, remote heli-rig exploration, HTHP completions and extended-reach
design for various major operators and clients. Mr. Hyatt has a BS degree in petroleum
engineering with honors from the University of Texas at Austin and is a life
member of SPE.
WILLIAM BRENDLING has a PhD in Applied Mathematics
and is a Fellow of the Institute of Mathematics and its Application. He has
been employed by BMT or predecessor companies for 40+ years. During that time,
he has worked on many offshore projects looking at environmental loading and
its impact on operational performance. Amongst other software projects, Dr.
Brendling is the primary architect of BMT’s SLOOP software for quantitative
simulation and assessment of the performance of offshore operations.