Copyright 2001, Offshore Technology Conference

This paper was prepared for presentation at the 2001 Offshore Technology
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Abstract

Many cost components must be considered to determine the most cost
effective deepwater production system for a particular site. Too often,
only the well systems CAPEX is adequately included in field development
alternative studies. OPEX, RAMEX and RISKEX depend largely on reservoir
characteristics, specific well system designs and operating procedures.
The effect of these factors nearly always outweigh differences in well
system CAPEX. Optimization of total lifecycle cost of deepwater
production systems must include all of these factors.

The risks associated with blowouts are often an important factor in
choosing one dry tree tieback well system over another. Another
important factor often overlooked is the cost of well system component
failures. As oil exploration and production moves into deeper and deeper
water, the costs to repair well system component failures escalate
dramatically.

This paper presents the methodology developed by a Joint Industry
Project to quantify capital, operational, blowout risk and reliability
costs associated with deepwater well systems. Five well systems have
been modeled to demonstrate the methodology: a dual casing dry tree
system, a single casing dry tree system, a tubing riser dry tree system,
a conventional tree subsea system and a horizontal tree subsea system.
Case examples demonstrate the model for these five well systems.

The methodology, results and main conclusions from this Joint Industry
Project are presented.

Introduction

This paper summarizes the work of a Joint Industry Project (JIP)
sponsored by five oil companies and the US Minerals Management Service
(MMS) to estimate deepwater field development lifecycle CAPEX, OPEX,
RISKEX, RAMEX, for subsea systems[^1]. An earlier JIP, The Dry Tree
Tieback Study (DTTAS) /1-4/, developed and demonstrated the methodology
to calculate CAPEX, OPEX and RISKEX for alternative dry tree tie-back
riser systems for Spars and TLP's. That study demonstrated the
importance of site-specific estimates of RISKEX, the probability of a
blowout during field life multiplied by cost of a blowout, when deciding
between single casing and dual casing riser systems.

In 1999 this JIP was initiated which broadened the scope of previous
work to include conventional and horizontal tree subsea well systems in
addition to Spar and TLP dry tree well systems. Most significantly,
RAMEX for both dry tree tiebacks and subsea systems is included in this
study. The methodology is especially useful for comparing alternative
field development scenarios.

The spreadsheet tool that was developed in the DTTAS JIP has been
expanded. The tool now expedites calculation of CAPEX, OPEX, RISKEX and
RAMEX. The multiple spreadsheet format permits simple screening of
alternative field development scenarios using built-in default values.
In addition, detailed site-specific evaluations are possible by easily
changing tabulated values for any data for which values that are more
accurate are known.

Numerous case examples have been evaluated for a variety of field
development scenarios. These studies have taught that a thorough
site-specific evaluation is required to determine the most economical
well system. The well system CAPEX, OPEX, RISKEX and RAMEX must be based
on a thorough evaluation of reservoir characteristics. Too often,
project personnel who select field development alternatives fail to
consider adequately the lifecycle implication of their selections.

This work demonstrates the importance of site-specific evaluations that
tailor the field development scenario to the unique reservoir
characteristics. An effective reservoir- centered development requires
thoughtful selection of a well system to acheive total lifecycle
operational requirements. Lifecycle operational requirements usually
involve significant well intervention activities.

Some wells do not produce as expected and must be replaced. "Planned
workovers" are required to re-complete to new zones because high
production rates of these wells result in relatively fast zone
depletion. Most reservoirs are layered and faulted. Most wells water-out
and/or production rates drop to uneconomical levels in a relatively
short time. For each zone, initial production rates, rate of production
decline and total recoverable reservoirs must be considered in a
lifecycle evaluation to ensure that future operational requirements are
not overlooked in the original planning.

Some well system component failures should be anticipated for all wells.
Tubing string leaks and sand control failures are inevitable and
stimulation operations may be required to maintain acceptable production
rates. Subsea wells must also contend with subsea facilities failures in
control system components, flying leads, manifold and tree valves,
flowlines, etc. However, we find subsea system failures are less severe
than sand control failures and stimulation needs that are common to both
dry tree and subsea wells.

Well system alternatives (dry trees, wet trees, dual casing risers,
single casing risers, etc.) should be considered as "tools" to develop a
deepwater oil or gas field. Each unique field development requires its
own set of well system "tools." A detailed site-specific evaluation is
required to determine the optimum "tools" for the most economical field
development.

Dry tree well systems become more vulnerable to loss of well control
with increased water depth (riser length and stresses). Larger and more
expensive platforms are required to support the larger risers.

Subsea well system repairs and interventions become more expensive and
are associated with longer delays due to reduced availability and
increased mobilization times for the required repair vessels.

Cost Model. The implications of disasters and business interruptions
should be incorporated into business decision analyses that seek to
evaluate the viability of alternative designs. Inclusion of these
\"unforeseen\" RISKEX and RAMEX elements with the usual CAPEX and OPEX
elements results in the economic model:

*Profit = Max (Revenue-CAPEX-OPEX--RISKEX-RAMEX)*

The methodology is developed to permit predictions of lifecycle cost for
a field development based on statistical and judgmental reliability data
and carefully estimated system parameters.

Some of the most difficult cost elements to calculate can be quickly and
easily estimated with this methodology. Other costs must be included
(platform and facilities cost, drilling costs, field operating costs)
for a complete evaluation.

Cost Elements Included. The following cost elements are considered for
both dry tree and subsea systems:

-   CAPEX includes capital costs of materials and installation of the
    wells and systems. Materials include dry tree risers with associated
    equipment such as tensioners for TLP's, air can buoyancy for Spar's
    and surface trees, subsea systems such as subsea trees, pipelines,
    pipeline end manifolds, jumpers, umbilicals and controls systems.
    Installation costs includes vessel spread cost multiplied by the
    estimated installation time and rental or purchase cost for
    installation tools and equipment.

-   OPEX includes operating costs to perform "planned" zonal
    recompletions. OPEX for these planned recompletions is intervention
    rig spread cost multiplied by the estimated recompletion time for
    each zonal recompletion. The number and timing of planned
    recompletions are uniquely dependent on the site-specific reservoir
    characteristics and operator's field development plan. This study
    has developed a methodology and spreadsheet tool that permits the
    user to use individual well reserves, initial production rates and
    production decline rates to "plan" a well recompletion schedule and
    to develop a total field production profile.

-   RISKEX is risk costs associated with loss of well control (blowouts)
    during installation, normal production operations and during
    recompletions. Risk cost is calculated as the probability of
    uncontrolled leaks multiplied by assumed consequences of the
    uncontrolled leaks.

-   RAMEX is reliability-availability-maintainability costs associated
    with well or system component failures. Both the "loss of
    production" costs and "failed component repair/replacement" costs
    are determined.

Cost Elements Excluded. Cost elements that are not included in this
study are:

-   Spar or TLP platform facilities materials and installation costs
    (platform, processing facilities, export risers and pipelines,
    drilling/workover rig capital cost, etc.).

-   Drilling costs.

-   Downhole completion equipment costs (packer, tubing, SCSSV, etc.).

-   Field operations costs such as platform maintenance, downhole
    treatment chemicals, production operations personnel and boats and
    helicopters.

These cost elements must not be ignored for a thorough evaluation of
field development alternatives. However, the cost elements that are
estimated by the methodology described in this paper are often the most
difficult to define and are critical in selecting the most economical
well system alternatives.

Methodology

The lifetime cost assessment methodology consists of the following
steps:

1.  Define field development plan.

2.  Define well system components.

3.  Develop an FMEA for the systems to identify leak paths and other
    potential component failures.

4.  Develop step by step procedures for well intervention operations.

5.  Calculate CAPEX.

6.  Calculate lifecycle OPEX.

7.  Calculate lifecycle RISKEX.

8.  Calculate lifecycle RAMEX.

9.  Calculate overall lifecycle cost (CAPEX, OPEX, RISKEX, and RAMEX).

Define field development plan. A realistic field description is the
first and most important estimate that must be made. Data are always
limited at this planning stage a project. There is often a tendency to
design the development plan based on what is "hoped for" rather than on
mature expert judgement of what is most likely. The following
information must be estimated with as much accuracy as possible:

-   Reservoir characteristics - size, shape, productive zones, fault
    blocks, water/gas drives, etc. that determine the number and
    location of wells.

-   For each well - depth, formation pressure, recoverable reserves,
    design production rate, production profile and specific completion
    requirements such as type of sand control system.

In active oil provinces, it is important to consider existing
infrastructure such as existing facilities to receive and process
production from the wells.

Define well system components. It is necessary to define the components
that comprise the well system. These components will form the basis of
the RAMEX methodology and the leak paths used in the RISKEX
calculations.

Typical downhole completion systems and dry tree tieback riser systems
were developed in the previous studies. Additional base case designs of
both conventional and horizontal tree subsea systems were developed in
this study. These detailed designs permitted the identification of all
well-control barriers and component seals for these typical systems.

Identify potential component failures with a FMEA. A Failure Modes and
Effects Analysis, FMEA, is required to identify and document the
failures and potential consequences for the well tieback system. This
FMEA provides the basis for developing fault trees to calculate RISKEX
and RAMEX.

Develop step by step intervention procedures. Operating procedures are
required for initial installation of completion systems, planned
workovers to new intervals as zones deplete, and unplanned interventions
to repair and/or replace failed components. Initial completion
procedures are used to calculate capital costs, CAPEX. Cost of planned
interventions, i.e., recompletions as zones deplete, is OPEX. Cost to
repair well system component failures is a major component of RAMEX.
Individual steps of all operating procedures define changes in the well
control barriers that provide the basis for risk costs, RISKEX.

The following procedures were developed for each dry tree tieback
alternative and subsea well system:

1.  Initial Installation of Frac-pack Completion

2.  Initial Installation of Horizontal Lateral Completion

3.  Pull completion, Install New Frac-Pack Completion

4.  Pull completion, Plug Lower Zone and Install Uphole Frac-Pack
    Completion

5.  Pull completion, Plug Lower Zone, Sidetrack and Re-complete with
    Frac-Pack

6.  Pull completion, Plug Lower Zone, Sidetrack and Re-complete
    Horizontal Well

7.  Repair Completion System Leaks (pull and rerun completion string)

8.  Repair/replace surface or subsea tree

9.  Coil tubing downhole repair

The following procedures were developed for subsea equipment
repairs/replacements:

1.  Repair pipeline or PLEM

2.  Repair/replace flowline jumper

3.  Repair/replace tree jumper

4.  Repair/replace hydraulic system umbilical

5.  Repair/replace electrical system umbilical

6.  Repair/replace well jumper

7.  Repair/replace well flying leads

8.  Repair/replace well control pod

9.  Repair/replace well subsea choke

10. Repair extension pipeline or PLEM

11. Repair/replace extension jumper

12. Repair/replace hydraulic extension umbilical

13. Repair/replace electrical extension umbilical

14. Repair/replace tree jumper extension

These procedures provide a broad cross section of the types of work
completed during the total field lifecycle. They can be tailored easily
to describe the operations for other well depths and water depths.

Calculate CAPEX. CAPEX is calculated as the sum of well system materials
and installation costs. The CAPEX for dry tree tieback alternatives
includes riser related component costs such as riser joints, tensioners
(including riser load cost penalty based on riser tension load), air can
buoyancy modules and wellheads. The riser load cost penalty was larger
for TLPs than for Spars because most Spar riser loads were supported by
air cans.

The dry tree alternatives materials costs include riser-related costs
for TLP or Spar and for dual casing risers, single casing risers and
tubing riser materials. The data are formulated to permit cost estimates
for various numbers of wells and various water depths.

CAPEX for the subsea well system includes pipelines between the subsea
wells and host facility, pipeline end manifolds, subsea production
manifolds, jumpers to connect the pipeline and manifold, hydraulic and
electrical umbilicals, well jumpers, and conventional subsea trees or
horizontal subsea trees. These basic CAPEX cost components for subsea
systems can be used to tailor a site-specific CAPEX estimate.

CAPEX also includes installation costs that are calculated from defined
vessel(s) spread costs multiplied by the vessel(s) operating time for
initial well interventions and initial subsea system installations.

Calculate lifecycle OPEX. Each of the identified intervention procedures
is broken into steps. The duration of each step is estimated from
historical data. The non-discounted OPEX associated with a re-completion
is estimated as:

*OPEX = (Intervention Duration) x (Rig Spread Cost)*

OPEX values are tabulated in the appropriated year that the expense
occurs to permit net present value, NPV, calculations.

Calculate lifecycle RISKEX. The RISKEX methodology developed in DTTAS
/3/ was used as a basis for determining the RISKEX for the subsea
completions.

The probability of failure of the well completion system is a function
of the probability of failure during the various operating modes
(drilling, initial completion, normal production, workovers and
re-completions). The lifetime probability of a blowout is calculated as:

$$\begin{array}{r}
P(\text{BO during lifetime}) = \text{ P}(\text{drilling}) + P(\text{initial compl}\text{.}) + \\
P(\text{prod}) + \sum_{}^{}{P(\text{WO})} + \sum_{}^{}{P(\text{re-compl}\text{.})}
\end{array}$$

The cost of a blowout depends on the size of the release ("Limited,
"Major" or "Extreme"). The Risk Cost (RC) associated with a certain
activity (j) is calculated as:

$$\text{RC}(j) = \sum_{i \in \left\{ \text{limited, major, extreme} \right\}}^{}{\text{Prob}_{i}(\text{activity j})\text{·C}_{i}}$$

where: Prob~i~ (activity j) is the probability of a blowout of size i
during activity j, and C~i~ is the cost of leak of size, i ∈ {limited,
major, extreme}.

Calculate lifecycle RAMEX cost. During a well's life, components can
fail that will require the well (and sometimes the entire system) to be
shut-in while the component is being repaired. The costs to the
operating company of these component failures are twofold:

-   The cost to repair the component (i.e. repair vessel spread cost
    multiplied by duration), and

-   The lost production associated with one or more wells being down.

The average cost per year associated with these unforeseen repairs is
called reliability, availability, and maintainability expenditures, or
RAMEX. The RAMEX of a particular component is calculated by multiplying
the probability of a failure of the component by the average consequence
cost associated with the failure (repair and lost production costs). The
system RAMEX is calculated by summing all of the component RAMEXs that
are included in the particular system.

The RAMEX calculation is performed through the following four steps:

1 - Identify components failures modes. A table of well system
components -- from the reservoir to the tubing hanger - is developed for
each completion system. Failure modes such as a sand control system
failure, tubing leak and SCSSV failure are determined.

Subsea completion equipment (i.e., manifolds, jumpers, etc.) can fail,
resulting in production loss from one or more wells. Because these
components can cause the downtime of more than one well, they are
modeled separately from the downhole components. Table 3 lists the types
of subsea repairs with the percent of wells affected.

2 - Identify costs associated with each repair operation. An FMECA
identified critical failure modes (mechanical failure, reservoir-related
failures, and regulatory driven shutdowns) and determined associated
consequences of failures for each well system component. This process
identified which operating procedure would be used to achieve the
repair. The operating procedure determined the duration of the repair
activity and the type(s) of repair resource(s) required for the repair.
These repair resources include platform rig, MODU, DSV, MSV, wireline or
coiled tubing unit, etc. Repair resource "availability time" (i.e., how
long before a resource vessel can be contracted to perform the
operation) and repair resource "spread costs" are estimated based on
local conditions. These are easily varied to determine their effect on
the total project economics. Well production lost/deferred while waiting
on repair resources and during the repair operation are dependent on the
number of wells affected by the component failure and on individual well
production rate(s) at the time of the failure.

3 - Determine the frequency of component failure. Component reliability
data that were developed for both RISKEX and RAMEX calculations
consisted of estimates of limited failures and extreme failures. For
example, a tubing joint has a probability of developing limited leak due
to minor damage or improper make-up and a less likely probability of an
extreme failure that results in rupture or parting.

All extreme failures were assumed to necessitate a workover. However, a
limited failure may or may not cause a stoppage of operations, depending
on the size and nature of the failure. Small leaks often cause pressures
to increase in the annulus between the tubing string and the production
casing. The U.S. Minerals Management Service (MMS) permits production to
continue with annulus pressure so long as the pressure build-up is
within certain limits. Leaks that are sufficiently small to permit
continued operations may eventually increase in size until sustained
annular pressure indicate loss of a well control barrier.

The fraction of limited failures that are severe enough to require a
workover is defined as the ξ-factor. The failure breakdown is shown in
the following.

![](media/image3.wmf)

The ξ-factor was estimated to correspond to historical experience. MMS
policy of "zero-tolerance" for annular pressure for single casing risers
mandate the need for a workover, regardless of the size of the leak.
Therefore, a ξ-factor of 1 is used for the single casing riser tieback
system.

4 - Determine cost of each subsea component failure. A field development
system is defined as a simplified, hierarchical network of completion
components. The field development system can consist of one or more
wells; the well can consist of one or more completion components.

A well is modeled as a list of completion components with their
associated failure modes, corresponding consequences in terms of reduced
production, and required repair resource. A well is considered to
function if all of its components are functioning (in reliability theory
referred to as a series structure). The type and number of completion
components may vary from well to well.

The frequency of unplanned workovers can be calculated using the RAMEX
methodology. Each component failure mode has a specific workover
associated with its repair. Using the component failure probabilities
described earlier, it is then possible to determine the frequency per
year of each unplanned workover. Unplanned repair frequencies are
calculated for the various types of repair operations.

RAMEX is calculated by multiplying the yearly system failure probability
by the costs associated with lost production and repairing the system
for the particular failure. This section will first describe the
calculation of the lost production costs, then describe the repair
costs.

The oil/gas production profiles vary over time. Each individual well
will have a normal production rate, which sums to the normal daily field
production rate. The individual well capacity can be larger than the
normal rate.

The production consequence for an individual well depends on the
following:

-   The production rate at the time the failure occurred

-   Lost capacity while waiting on repair resources

-   Availability time for the repair resources

-   Active repair time

The average production loss per year due to any particular component is
given by the following equation:

$$\text{PL}_{\text{year}} = \frac{P_{a}(H) - P_{a}(L)}{\text{1 year}} \ast (T_{\text{AR}} + T_{\text{RA}}) \ast \text{PR} \ast 3\text{65 days/year}$$

where: PL~year~ = the production loss cost for a given year, P~a~(H) =
the probability of component failure for the end of the year (e.g. 2 for
year 1), P~a~(L) = the probability of component failure for the
beginning of the year (e.g. 1 for year 1), T~AR~ = the mean time to
repair a certain failure, T~RA~ = the rig availability time, PR = the
average well flow rate for that particular year.

The average production loss per year for a given well is the sum of the
losses for all the well components. This concept of lost production is
further illustrated in the following figure, where: TTF = Time To
Failure, LCWR = Lost Capacity while Waiting on Rig, T~RA~ = Resource
Availability Time, T~AR~ = Active Repair Time).

![](media/image4.wmf){width="3.5993055555555555in"
height="1.9097222222222223in"}

The mean time to repair is dependent upon the operation used to repair
the system. A repair operation is required for each component failure.

Each operation will have a corresponding repair vessel, depending on the
scenario (dry tree, subsea).

A field production profile prediction provides the basis for a field
development plan. This field total production rate prediction is the sum
of the individual well production rates. Processing facilities capacity
typically limits the field production rate during a "plateau" period
when many wells are producing at near maximum rates. The production
profile will normally represent a "zero equipment failure" scenario and
its production volume over the planned lifetime can be regarded as
"ideal recoverable reserves".

If the processing facility capacity, at the time of a well failure, is
lower than the rate that can be produced by the non-failed wells, there
is no loss in production rate. This will normally be the case during the
plateau period. However, if the processing facility capacity, at the
time of the failure, is higher than the rate that can be produced by the
non-failed wells, failure will result in a loss of production rate. This
will normally be the case in the period before the plateau period
(drilling and tie-in of new wells) and the decline phase after the
plateau period.

If the total remaining well flow rate exceeds the production capacity by
more than the flow rate of the failed well, the production loss is
ignored. However, if the flow rate of a particular well is more than the
difference between the total well flow rate and the processing facility
capacity, the lost production is the difference between the total field
flow rate and the particular well flow rate. For calculation purposes,
the following algorithm has been used:

$$\text{LP} =$$

where: LP = lost production for a field in a particular year (BOPD),
PR~lost\ well~ = the production rate of a failed well (BOPD),
PR~remaining~ = the production rate of the rest of the wells (all minus
the failed well) (BOPD), PFC = the production flow capacity (BOPD).

The repair costs is calculated by multiplying the yearly system failure
probability by the mean time to repair the failure and the rig spread
cost. For each component failure, there may be a different resource
associated with the repair, and hence a different cost. The repair cost
is calculated by using the following equation:

$$\text{RC}_{\text{year}} = \frac{P_{a}(H) - P_{a}(L)}{\text{1 year}} \ast T_{\text{AR}} \ast \text{RSC}$$

where: RC = resource cost associated with a particular failure, T~AR~ =
the mean time to repair a particular component, RSC = resource spread
cost (\$/day).

The final RAMEX values are calculated by multiplying the yearly failure
probability by the sum of the production costs and the repair costs for
a particular failure. This is shown in the following equation:

$$\text{RAMEX}_{\text{year}} = \sum_{\text{component failures}}^{}\frac{P_{a}(H) - P_{a}(L)}{\text{1 year}} \ast \left\{ \left\lbrack \left( T_{\text{RA}} + T_{\text{AR}} \right) \ast \text{LP} \ast \text{365} \right\rbrack + \left( T_{\text{AR}} \ast \text{RSC} \right) \right\}$$

where: RAMEX~year~ = the total RAMEX of a particular system for a
particular year.

The % uptime is defined as the percentage of the maximum flow that can
be expected during the field's lifetime. This percentage is calculated
by dividing the well-days attributed to lost production from the total
number of well-days during the field's life.

The calculation for the % uptime of a dry tree system is shown through
the following equation:

$$\text{\% uptime}_{\text{drytree}} = 1 - \frac{\sum_{x = 1}^{n}\frac{\text{LPD}_{x}}{W_{x}}}{D_{\text{total}}}$$

where: % uptime~drytree~ = the percentage of maximum flow expected from
dry tree wells during the field's lifetime, LPD~x~ = the days of lost
production in a given year (x) for the dry trees calculated through
RAMEX techniques, W~x~ = the number of subsea wells for a given year,
D~total~ = the total number of days for a field during it's lifetime.

The calculation of the % uptime of a subsea system is shown through the
following equation:

$$\text{\% uptime}_{\text{subsea}} = 1 - \frac{\sum_{x = 1}^{n}\text{LPSE}_{x} + \sum_{x = 1}^{n}\frac{\text{LPSW}_{x}}{W_{x}}}{D_{\text{total}}}$$

where: % uptime~subsea~ = the percentage of maximum flow expected from
subsea wells during the field's lifetime, LPSE~x~ = the days of lost
production in a given year (x) for the subsea equipment calculated
through RAMEX techniques, LPSW~x~ = the days of lost production in a
given year (x) for the subsea wells calculated through RAMEX techniques.

**Calculate overall lifecycle cost (CAPEX, OPEX, RISKEX, RAMEX).** The
CAPEX, OPEX and the Risk Cost will appear during different times in the
field life. The net present value of future costs was used to take the
time value of money into account. The lifetime cost was calculated by:

$$\begin{array}{r}
\text{Lifecycle  Cost } = \text{ CAPEX } + \text{ OPEX } + \text{ RISKEX} + \text{RAMEX} \\
\text{ CAPEX } + \sum_{k \in \left\{ \text{1,N} \right\}}^{}\frac{\text{OPEX}_{k}}{{}^{{(1 + r)}^{k}}} + \sum_{k \in \left\{ \text{1,N} \right\}}^{}{\frac{\text{RISKEX}_{k}}{{}^{{(1 + r)}^{k}}} + \sum_{k \in \left\{ \text{1,N} \right\}}^{}\frac{\text{RAMEX}_{k}}{{}^{{(1 + r)}^{k}}}}
\end{array}$$

where: OPEX~i~ and RC~i~ represent the OPEX and Risk Cost in year i
respectively, r is the discount rate and N is the field life in years.

Base Case Subsea System

A 6-well satellite clustered subsea system design was developed to
demonstrate the model. Figure 1 shows the overall layout for the base
case 6-well subsea system. The subsea system includes hydraulic and
electrical umbilicals and pipeline connecting the subsea system to a
remote host platform. Flowline jumpers connect the pipeline end
manifolds to a 6-well manifold and well jumpers connect the manifold to
individual wells that are clustered around the manifold. Hydraulic and
electrical flying leads connect the hydraulic and electrical termination
units to individual wells.

The methodology and spreahseet tool has been expanded to model
additional subsea facilities with pipeline umbilical extensions to an
additional subsea manifold with associated wells. This permits the
evaluation of a variety of subsea configurations and numbers of wells.

A schematic of the conventional tree used in the base case is displayed
in Figure 2. The tree consists of a 4-inch vertical access production
bore with wireline plug access to the tubing hanger via the tree. The
annulus bore is 2-inch nominal with direct wireline access to the tubing
hanger annulus.

The horizontal tree connects directly to the subsea wellhead system. The
horizontal tree design eliminates a tubing head spool as presently found
in the base case vertical tree system. The horizontal tree assembly will
carry the flowline hub enabling vertical well jumper connections between
the tree and manifold. Figure 3 displays the base case horizontal tree
configuration.

Case Examples

The methodology and spreadsheet program developed by this JIP has been
used to quantify the CAPEX, OPEX, RISKEX and RAMEX factors that
determine the differences in these well systems. The following sections
describe results and conclusions derived from evaluation of numerous
case examples.

***Dry Tree Tieback Systems.*** We have compared three dry-tree well
systems for a case example: dual casing riser, single casing riser and
tubing riser. The base case input data are summarized in Table 1 and the
lifecycle costs are presented in Table 2 and Figure 4. The results
indicate that a dual casing riser is the most cost efficient. The single
casing system is differentiated by its high RISKEX and the tubing riser
system is differentiated by its high OPEX and RAMEX. Note, however, that
the base case is located in deep water (4000 feet) and produces from a
high-pressure reservoir.

Single casing risers provide an ideal solution for shallow water and
moderately deep water when formation pressures are very near seawater
gradient. Because well interventions are performed with a surface BOP
stack through the single casing riser, a small leak in a single casing
riser can cause loss of well control in deepwater when formation
pressures are abnormal. RISKEX during well intervention operations is
quite high in this case. RAMEX is higher than for a dual casing riser
because any annular pressure requires an immediate intervention.

Dual casing risers provide the added well control for intervention
operation to minimize RISKEX. Well interventions are performed with a
surface BOP stack through the dual casing riser. CAPEX is typically \$1
to \$2 million dollars per well more than a single casing riser in
moderate water depths. OPEX for dual casing risers is slightly higher
than OPEX for single casing risers are because it takes a bit longer to
install the inner riser. RAMEX for dual casing risers is less than RAMEX
for single casing riser because production can continue with small
annular pressures. When CAPEX, OPEX, RISKEX and RAMEX are all considered
the dual casing riser system is the most economical alternative for
deepwater developments where reservoirs are abnormally pressured.

The tubing riser system includes a master valve (essentially a subsea
tree) at the mudline to provide well control in the event that the
tubing riser or surface tree leaks. This system has great attraction to
platform designer because it might significantly reduce the riser load
carried by the platform. This could significantly reduce platform size
and cost. Well interventions require the tubing and subsea master valve
to be removed and a well intervention riser system is installed. We have
considered two well intervention riser systems: (1) a high pressure
single wall riser with seafloor shear ram and surface BOP stack and (2)
a dual wall drilling riser. Tubing riser system OPEX is significantly
higher than dual or single casing riser systems because of additional
rig time needed to change these riser systems before and after any well
intervention. A moonpool is required in the platform to run a
conventional subsea master valve system or subsea shear ram. An
umbilical for annular access, and controls for the subsea master valve,
SCSSV, and other downhole components will be about the size of the
tubing riser. This dual-parallel riser configuration presents
significant problem in analyzing for vortex induced vibration. This
single-wall riser may also experience problems of hydrate or paraffin
plugging due to cooling.

***Subsea Production Systems***. The results of a case example of subsea
well systems are shown in Table 4 and Figure 3. Input data presented in
Table 1 were used for this example. The results indicate that the
horizontal tree system is the most economical for the base case and both
cases are dominated by the RAMEX.

Horizontal subsea tree system permits workover operations without
removing the subsea trees. This system is most economical if numerous
workovers are required for recompletions to new zones.

Conventional subsea trees can be replaced more easily than horizontal
trees in the event of the failure of a tree valve or actuator.
Conventional subsea trees can be replaced without pulling the
completions string; horizontal subsea trees require the completion
string to be pulled prior to pulling the tree. Therefore, the most
economical type of tree is influenced by the reliability of the tree
components such as valves, valve actuators, connectors, etc.

Subsea production systems have several unique advantages. CAPEX can be
much less than for a new platform facility when an existing facility is
available to accept production from a subsea production system. RISKEX
is relatively low for subsea systems. Table 4 and Figure 3 show that
RAMEX and OPEX can be significantly higher than dry-tree systems,
depending on reservoir characteristics. The daily spread cost for a MODU
is about twice that of a platform rig operation and it takes almost
twice as long for most well interventions. Handling subsea BOP's and
marine risers takes much longer than dry-tree intervention operations.
Therefore, subsea well interventions cost three to four times as much as
dry-tree interventions.

Smart completions may be useful to minimize RAMEX for subsea wells.
Smart or intelligent completions have the potential to:

-   Remotely and inexpensively isolate a depleted zone and initiate flow
    from a new productive zone, regulate the flow from adjacent zones to
    maximize recoveries and reservoir performance, remotely achieve
    other changes in downhole configurations.

-   The use of a smart completion for zonal re-completion when the
    primary zone is depleted provides the potential to eliminate an
    expensive workover.

This potential saving is partially offset by several smaller costs. The
alternate zone must be properly completed with an appropriate sand
control system, thus, increasing the initial well cost and perhaps
delaying production. Reservoir characteristics are better understood
after several years of production, thus, permitting improved
re-completion designs. Smart completion tools cost more to install and
because of increased complexity are more likely to fail, requiring an
unplanned workover.

The net present value (NPV) of a smart completion CAPEX must be compared
to the NPV of a later workover and the system RISKEX and RAMEX to
determine the most cost effective development plan.

Acknowledgements

The Joint Industry Project (JIP) team for the "Lifetime Cost of Subsea
Production Systems" project wishes to acknowledge the participation and
assistance from the representatives from the following companies:

-   Arco Exploration and Production Technology (now BP Amoco)

-   BHP Petroleum Americas, Inc.

-   Chevron Petroleum Technology Co.

-   Conoco Inc.

-   Elf Exploration Inc.

-   Minerals and Management Service

Their assistance, guidance and expert knowledge contributed greatly to
the achievement of the goals for the project.

References

/1/ Alan H. Woodyard, "Risk Analysis of Well Completion Systems,"
Journal of Petroleum Technology, April 1982, pp. 713-720.

/2/ Joint Industry Project, "Risk Assessment for Dry Tree Tieback
Alternatives," Phase 2 Study Final Report, March 1998.

/3/ R. Goldsmith, R. Eriksen, F. J. Deegan, "Lifetime Risk-Adjusted Cost
Comparison for Deepwater Well Riser Systems" presented at OTC in Houston
May 1999 (OTC 10976).

/4/ Remi Eriksen and Riley Goldsmith, "Selecting Deepwater Drilling and
Production Riser Systems with Lowest Total Field-Life Cost" presented at
Deep Oil Technology Conference, Stavanger, Norway, October 1999.

/5/ Joint Industry Project Proposal "Lifetime Cost of Subsea Production
Systems". Distributed by Det Norske Veritas, Houston, USA

/6/ Remi Eriksen and Brian Saucier, "Selecting Cost-Effective and Safe
Deepwater Completion Tieback Alternatives," presented at OTC in Houston,
May 2000 (OTC 12167).

Terms and Acronyms

CAPEX -- CAPital EXpenditures

DSV -- Drilling Service Vessel

DTTAS -- Dry Tree Tieback Alternative Study

FMEA -- Failure Modes and Effects Analysis

FMECA -- Failure Modes, Effects, and Criticality Analysis

JIP -- Joint Industry Project

MMS -- Minerals and Management Service

MODU -- Mobile Offshore Drilling Unit

MSV -- Multi-Service Vessel

PLEM -- Pipeline End Manifold

OPEX -- OPerational EXpenditures

RAMEX -- Reliability-Availability-Maintainability EXpenditures

RISKEX -- RISK EXpenditures

TLP -- Tension Leg Platform

ξ- factor -- Ratio of limited leaks that will necessitate a workover

AXV -- Annulus cross-over valve

PWV -- Production wing valve

AV -- Annulus vent

LMV -- Lower master valve

PSV -- Production safety valve

CID -- Chemical injection downhole

CIT -- Chemical injection tree

FIV -- Flowline isolation valve

AMV -- Annulus master valve

ASV -- Annulus swab valve

AWV -- Annulus wing valve

Figure 1: Satellite Cluster

![](media/image5.wmf)

Figure 2: Conventional/Vertical Tree Schematic

![](media/image6.wmf){width="4.31875in" height="5.591666666666667in"}

Figure 3: Horizontal Tree Schematic

![](media/image7.wmf){width="4.475in" height="5.960416666666666in"}

Table 1: Case Study Input Data

  -------------------------------------------------------- --------------
                                                           **INPUT DATA**

  Field Life (years)                                       10

  \# of wells                                              6

  Water depth (feet)                                       4,000

  Zone depth (feet BLM)                                    10,000

  Pipeline size (in) - for subsea equipment                12

  Pipeline length (mi) -- for subsea equipment             35

  Infield extension (mi) -- for subsea equipment           5

  Facilities processing limit (MBOPD)                      No limit

  Oil op. margin in year produced (\$/bbl)                 8

  Discount rate for NPV calculations (%)                   15

  Number of unplanned tree replacements                    2

  Number of unplanned downhole repairs                     2.5

  Number of unplanned sand control repairs                 5

  Recoverable reserves per zone (MM BO)                    22

  Initial production rate (M BOPD)                         15

  Decline rate (%/year)                                    10

  Ratio frac pack -- horizontal wells                      1:1

  Ratio planned uphole frac packs--sidetrack frac          1:1:1
  packs--sidetrack horizontals                             

  Limited uncontrolled release cost (\$ / BOPD)            \$1,700

  Major uncontrolled release cost (\$ / BOPD)              \$35,000

  Extreme uncontrolled release cost (\$ / BOPD)            \$250,000
  -------------------------------------------------------- --------------

Table 2: Dry Tree Completion Alternatives RAMEX Results -- 6 wells, 4000
ft

+---------------------------+-------------+-----------+--------------+
|                           | **DUAL      | **SINGLE  | **TUBING     |
|                           | CASING**    | CASING**  | RISER**      |
+---------------------------+-------------+-----------+--------------+
| \% Uptime                 | 98.0 %      | 97.8 %    | 97.8 %       |
+---------------------------+-------------+-----------+--------------+
| Repair Cost (\$MM)        | 11.4        | 12.0      | 15.7         |
+---------------------------+-------------+-----------+--------------+
| # Production Lost (\$MM)  | 25.6        | 29.1      | 28.9         |
+---------------------------+-------------+-----------+--------------+
| **Total RAMEX (\$MM)**    | **37.0**    | **41.1**  | **44.6**     |
+---------------------------+-------------+-----------+--------------+

Figure 4: Dry Tree Completion Alternatives Lifecycle Cost (\$MM NPV)-- 6
wells, 4000 ft

![](media/image8.wmf){width="3.8979166666666667in"
height="2.5027777777777778in"}

Table 3: Subsea Equipment Repair Costs

  ---------------------------------------------------- ------------------
  **Subsea Repair Type**                               **% of Wells
                                                       Affected**

  Repair / Replace Hydraulic System Umbilical          100%

  Repair / Replace Electrical System Umbilical         100%

  Repair / Replace Hydraulic Extension Umbilical only  100%
  if \> 8 wells                                        

  Repair / Replace Electrical Extension Umbilical only 100%
  if \> 8 wells                                        

  Repair Pipeline or PLEM                              50%

  Repair / Replace Flowline Jumper                     50%

  Repair Extension Pipeline or PLEM only if \> 8 wells 50%

  Repair / Replace Extension Jumper only if \> 8 wells 50%

  Repair / Replace Tree Jumper Extension only if \> 8  One well
  wells                                                

  Repair/ Replace Tree Jumper                          One well

  Repair / Replace Well Jumper                         One well

  Repair / Replace Well Flying Leads                   One well

  Repair / Replace Well Control Pod                    One well

  Repair / Replace Well Subsea Choke                   One well
  ---------------------------------------------------- ------------------

Table 4: Subsea Completion Alternatives RAMEX Results -- 6 wells, 4000
ft

+--------------------------------+-------------------+----------------+
|                                | **CONVEN-TIONAL   | **HORIZON-TAL  |
|                                | TREE**            | TREE**         |
+--------------------------------+-------------------+----------------+
| \% Uptime                      | 89.6 %            | 89.6 %         |
+--------------------------------+-------------------+----------------+
| Repair Cost (\$MM)             | 69.4              | 64.1           |
+--------------------------------+-------------------+----------------+
| # Production Lost (\$MM)       | 132.3             | 131.9          |
+--------------------------------+-------------------+----------------+
| **Total RAMEX (\$MM)**         | **201.7**         | **196.0**      |
+--------------------------------+-------------------+----------------+

**Figure 3: Dry Tree Completion Alternatives Lifecycle Cost (\$MM NPV)--
6 wells, 4000 ft**

![](media/image9.wmf)

[^1]: Definitions of terms and acronyms are listed at the end of the
    paper.