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Optimum Development in Mature Fields:
Sanga-Sanga Assets, Indonesia
V
ICO Indonesia is the operator
of the Sanga-Sanga productionsharing contract (PSC) in Indonesia.
Against a backdrop of of 46% annual
base decline, VICO generated and
implemented an integrated and
aggressive work program called the
Renewal Plan. This is an integrated
approach between reservoir
management and technology
application. This plan proved to
be an efficient example of better
reservoir management for optimum
development of mature assets.
monobore, and horizontal). The surface facilities supporting the production
include four main production centers,
12 gathering stations, and more than
90 compressors.
After 40 years of production, these
fields have now reached a fairly mature
stage; most of the penetrated reservoirs/
tanks have been depleted from original pressures. Coupled with the annual
production decline, this condition has
resulted in significant challenges to delivering a continuous economic and efficient field-development strategy while
maximizing field production.
Introduction
Renewal Plan
The Sanga-Sanga acreage is located onshore in the Mahakam delta, East Kalimantan, Indonesia. The acreage is located within the Kutai basin, which is
characterized by the Samarinda anticlinorium, with a series of highly prolific anticlines. Hydrocarbon accumulations are most often located within a
series of mid-Miocene upper-delta and
delta-plain sandstone reservoirs, and
are principally characterized by fourway dip closure or two-way structural/
stratigraphic traps.
VICO Indonesia has been exploring and developing this PSC acreage actively since 1968. There are seven producing fields (Fig. 1): Badak, Nilam,
Semberah, Mutiara, Beras, Pamaguan,
and Lampake. These together produce
385 MMscf/D of gas and 14,500 B/D
of liquids from 420 active wells, which
have mixed wellbore completions (single, d
­ual-selective, monobore, dual-
VICO carried out a reserves-reassessment
study—an integrated approach involving
reservoir management and technology
applications conducted by a multidisciplinary team. The seven components of
the Renewal Plan are described in the following subsections.
Securing Base Production. Securing base production is one of the keys
to achieving a production target. Well
monitoring and surveillance are the
primary methods by which base production is secured. Previously, VICO
wells were monitored by frequent production tests, mostly depending on
human surveillance.
In the Renewal Plan, automated
­real-time monitoring well surveillance
of wellhead-pressure and flow-rate data
on each well was impemented. This
­real-time wellhead surveillance (RTWHS)
transmits the data from the wellsite to
This article, written by JPT Technology Editor Chris Carpenter, contains highlights
of paper SPE 158716, “Renewal Plan: Efficient Strategy for Optimum Development
in Mature Fields—A Success Story From Sanga-Sanga Assets, Indonesia,” Andre
Wijanarko, Bambang Ismanto, and Robhy Permana, VICO Indonesia, and Italo
Pizzolante, Eni, prepared for the 2012 SPE Asia Pacific Oil and Gas Conference and
Exhibition, Perth, Australia, 22–24 October. The paper has not been peer reviewed.
the VICO server; then, it is stored in a
data­base. Operators and production engineers could monitor the behavior of
the well in real time. This system has
proved to minimize well downtime, leading to aggressive well reactivation.
This installation has also become
standard for new wells. Currently, 90%
of VICO’s active wells are equipped
with RTWHS.
Aggressive Drilling Plan. The multidisclipinary team concluded that remaining potential reserves are high, even
though the PSC acreage has produced
70% over 40 years. New well development can be carried out by means of
­conventional-well, grid-based-drilling,
and cluster-drilling methods.
Previous VICO completion design
used single-/dual-string 2⅞-, 2⅜-, and
3½-in. completion with multipackers
installed for single/multiple perforation.
This led to commingled production from
several zones, reducing the maximimum
potential of each individual zone. The
single 4½-in. monobore offered better reservoir management and a single
production tubing, with the annulus cemented up to surface. The downside of
the 4½-in.-monobore completion, however, includes less flexibility to catch up
with the deliverability target.
A dual 3½-in.-monobore completion was implemented, and flexibility
of the production strategy was achieved
by use of long strings for maximizing
reserves recovery, and short strings
for optimizing production. This dual
3½‑in. monobore has become a standard well completion in VICO Indonesia’s portfolio.
Aggressive Rigless Development.
While maintaining base production, optimization of existing wells is the priority for meeting the production target. To
that end, on a routine basis, the multi­
For a limited time, the complete paper is free to SPE members at www.spe.org/jpt.
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MFW158716.indd 86
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1600
Compress to VLP
Compress With Wellhead Compressor
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1400
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0
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Gas, Mcf/D
Fig. 1—Sanga-Sanga PSC.
disciplinary team evaluated potential
wells along with underperforming wells,
idle wells, and bypassed zones.
For underperforming wells, a detailed review was conducted to determine
the causes of production decline. Static/
flowing bottomhole and productionlogging data are useful in this task;
nodal-analysis and material-balance
software were used to support review
findings. For idle wells, a detailed review is performed to evaluate existing
producing zones and remaining potential zones.
A bypassed zone is a potential productive zone that was not interpreted as
a hydrocarbon zone in the past. These
zones are reviewed on the basis of log
data, offset-well production, and mudlog data compiled during drilling.
Low-Permeability Exploitation. One
of the Renewal Plan objectives is to regain production and increase the reserves recovery from low-permeability
zones. Because most of the fields have
reached a mature stage at which the
shallow and middle layers have been
88
MFW158716.indd 88
Flowing Tubinghead Pressure, psig
1300
0
300
1500
Date
Flowing Tubinghead Pressure, psig
Fig. 2—Wellhead compressor.
produced and depleted significantly, the
remaining reserves are spread over the
deeper low-permeability sands, where
previous completion approaches have
not effectively depleted the reserves.
A comprehensive approach was
identified that ranks the candidate reservoirs for low-permeability development.
Additionally, several low-­permeability
gas-development strategies and technologies have been evaluated and executed since 2006. These low-­permeability
technology ­
applications pertained to
horizontal wells, hydraulic fracturing,
and radial drilling/jetting.
Deliquification. A large proportion of
VICO’s existing well production is subject to liquid loading, leading to premature abandonment of producing zones;
and some wells have to be in cyclic production. Liquid loading of a gas well
is the inability of produced gas to remove the produced liquids from the
wellbore, leading to excessive backpressure on the production interval, which
in turn reduces productivity. This situation is influenced by tubing size, sur-
face pressure, and the amount of associated liquids being produced with
the gas.
Historically, VICO’s approach to
well reactivation/deliquification included low-cost, low-technology solutions
such as venting, cycling, gas injection,
and soap sticks, used with mixed success. In 2006, in new-technology trials,
the installation of capillary-string injection in liquid-loaded wells was tested.
The capillary-string-injection concept introduces a foaming agent into
the wellbore through ¼-in. capillary
strings and injects the surfactant across
the perforation. The foaming agent is
then mixed with produced fluids, reducing the density of the liquid, increasing
the gas velocity, and improving the ability of the well to produce liquids and
have stabilized gas flow. This capillarystring chemical injection was chosen
because its relatively simple application
also can be implemented in a wide range
of VICO’s completions (monobores,
dual-string completions with nipple
profiles, and selective completions produced through sliding sleeves).
JPT • JANUARY 2014
12/12/13 1:37 PM
Fieldwide capillary-string-injection installation has been
implemented since 2006. Currently, there are 65 capillarystring-injection installations, which have successfully maintained ­liquid-loaded-well production with continuous flow (instead of a cyclic mode) to deliver 16 MMscf/D.
Oil Development. The aggressive drilling program in Mutiara
and Pamaguan fields resulted in an increase of oil reservoirs to
be produced. A gas lift system is the preferred method used to
achieve artificial lift because VICO has abundant gas resources.
Because monobore wells have no annulus (they are cemented
up to surface), there is no gas-lift-valve/side-pocket-mandrel
configuration available to introduce gas lift into the production tubing.
A solution for developing oil in a monobore well completion involves use of smaller-inside-diameter coiled tubing (normally 1½-in. diameter) inside the production tubing, which includes special bottomhole assemblies (nozzle,
­dual-flapper check valve, and nipple). A special tubing hanger
is attached to the top of the tree to hold the inserted coiled tubing. This application is known as permanent-coiled-tubing gas
lift (PCTGL), which allows gas lift injection into the production tubing.
This method does not require the well to be recompleted with a rig, thus having significant cost savings and delivering desired oil production. During 2010–2011, 16 units of
PCTGL were installed, successfully sustaining 3,500 B/D of
oil production.
Facility Optimization. To maximize reserves recovery with
the condition that most of the production comes from depleted reservoirs, several attempts to lower abandonment pressure were made. Lowering the flowing wellhead pressure will
keep the well flow above the critical and liquid-loaded rates for
a longer period of time. To assist in this effort, VICO has categorized four different pressure systems:
1. High-pressure compressor with an inlet pressure of
700 psi and an outlet pressure of up to 1,500 psi
2. Medium-pressure compressor with an inlet pressure of
280 psi and an outlet pressure of up to 710 psi
3. Low-pressure compressor with an inlet pressure of
100 psi and an outlet pressure of up to 320 psi
4. Very-low-pressure (VLP) compressor with an inlet
pressure of 25 psi and an outlet pressure of up to
120 psi
Before 2006, only a few VLP compressors were available.
Consequently, some of the wells prematurely ceased flowing
because of an inability to flow in lower-pressure systems. Several studies were performed to determine how to lower fieldabandonment pressure, improve well productivity and reserves, and better manage a gas field’s natural decline. These
studies resulted in additional VLP compressors and indeed in
the categorization of another compressor with pressure lower
than that of a VLP system—called an extreme-low-pressure
compressor (wellhead compressor). Having wellhead compressors installed at the wellsite reduces the flowing wellhead pressure further (Fig. 2). JPT
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