SPE 132855
Optimizing Well Productivity and Maximizing Recovery from a Mature Gas
Field: The Application of Wellhead Compressor Technology
Sumaryanto, SPE, Ade Lukman, SPE, I Nyoman Hari Kontha, SPE, Bill Turnbull, SPE; VICO Indonesia
Copyright 2010, Society of Petroleum Engineers
This paper was prepared for presentation at the SPE Asia Pacific Oil & Gas Conference and Exhibition held in Brisbane, Queensland, Australia, 18–20 October 2010.
This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been
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Abstract
Introduction
VICO Indonesia is an Oil and Gas company which has
operated the Sanga-Sanga Production Sharing Contract
(PSC) in East Kalimantan, Indonesia, since 1968. More
than 750 development wells have been drilled to date in
the harsh swampy environment of the Mahakam Delta in
East Kalimantan. Today, the mature reservoirs are
predominantly gas, extremely depleted, and have an
average recovery factor of 70%.
The flowing tubing head pressure (FTHP) for wells in
these developments are typically 50 to 60 psi, allowing for
a potential reservoir abandonment pressure of
approximately 300 psi. The reservoirs are depletion drive
gas reservoirs. Through the installation of wellhead
compression, further lowering the FTHP, a lower
abandonment pressure was obtained and consequently
reserves recovery increased through well life extension.
In 2008, VICO installed 19 wellhead compressors,
achieving FTHP's as low as 5 psi. This resulted in
increased productivity, individual well production stability
and an expected improvement in overall recovery volumes
from the reservoirs. The compressors installed have a
small footprint (3.4 x 8.5 m), low fuel consumption and
minimal operating costs. Each unit has a nominal capacity
of 1 MMscfd. Through the careful well selection process
and the ability to quickly relocate the compressors to
different wells has enabled Vico to maximize the benefit
of this technology.
The paper will present the benefits of wellhead
compression in mature gas fields, the selection process for
the wells and the compressors, and the operational
challenges faced by the project.
VICO has been producing primarily gas with some oil for
approximately 38 years from several types of reservoirs.
The majority of the gas production today comes from
depleted reservoirs with declining gas production rates.
High regional gas demand and commodity prices drive the
requirement to find solutions to sustaining productivity
from existing wells for as long as possible.
One such solution is lowering the flowing tubing head
pressure (FTHP) of a well which keeps the well flowing
above the critical rate for a longer period of time. Vico
has installed compressors with low suction pressure near
to the wellheads to lower the FTHP in selected late life gas
wells.
A compressor design with a relatively small foot print was
selected to enable easy relocation between wells. Since
Vico’s depletion drive reservoirs produce wet gas, it was
required to equip the compressors with a separator or
scrubber which was capable of handling the liquid
production,- both water and condensate. The remote nature
of Vico's operations led to a strong preference for a low
maintenance compressor design.
Well Candidate and Compressor Selection
In determining both the well candidates and the type of
compressor package, it was necessary to categorize
producing wells by gas rate and liquid production. The
capacity, the suction and discharge pressure, and the liquid
characteristics determined the power requirement and type
of compressor. The suction pressure was required to be
low enough to keep the well flowing above its critical rate
to prevent it dying due to liquid load up.
2
Turner et. al.1 proposed two physical models for predicting
when a gas well will experience liquid load up: one based
on liquid film movement along the pipe walls; and the
other based on liquid droplet entrainment in a highvelocity gas. Using theoretical particle and drop-break-up
fluid mechanics, they calculated the minimum gas velocity
required to remove either water or condensate
continuously from wellbore. When the flowing rate is
above critical velocity, it is predicted that the droplets are
being carried up the well by the gas and are not
accumulating in the well. Conversely, if the rate is below
the critical velocity, then the droplets will accumulate in
the well. The well may actually not cease to flow if the
rate is below critical, but its production rate will decrease.
Based on the Turner equation for calculating the minimum
gas velocity, the critical gas rate for 3-1/2 inch tubing is
0.3 MMscfd, and 0.2 MMscfd for 2-3/8 inch OD tubing.
Wells flowing at a minimum gas rate of 0.3 MMscfd were
selected as wellhead compressor candidates.
Nodal Analysis2,3 was used to estimate the gas flow rate
for any flowing tubing head pressure. Several well
candidates were assessed to determine optimum
compressor capacity. The result of the analysis, confirmed
by well test data, was used to define the separator capacity
for the liquid handling facilities on the compressor skid.
Material Balance software was used to forecast the
production profile up to a certain abandonment pressure.
From this, project life and incremental reserves were
calculated to allow economic evaluation of the project.
Final well candidate selection was based on forecast
incremental rate and reserves.
SPE 132855
receives gas feed from the suction scrubber which
removes any liquid and particulate from the gas. The
liquids are drained from the vessel into the blowcase while
the gas is routed to the compressor. The gas is mixed with
lube oil during the compression cycle, and after
compression, the lube oil/gas mixture is directed to the oil
separator where the lube oil is removed from the gas. The
compressed gas is directed to the fin-fan heat exchanger
where it is cooled before going off skid to the field piping.
The lubricating oil circulates within a closed-loop system.
From the oil separator, the oil enters the oil/glycol cooler,
and then passes through a filter before returning to the
compressor. The temperature of the lube oil returning to
the compressor is kept constant by a thermostatic valve.
An engine driven pump circulates the glycol to the fin-fan
heat exchanger, where the additional heat of compression
is removed.
The lube oil is sensitive to surfactant which causes it to
lose its viscosity, and this removed wells which had
downhole surfactant injection from the well candidate list.
The presence of water in the lube oil can lead to plugging
of the lube oil filter, which could shut the compressor
down.
To address this, keeping the oil separator
temperature above 210 deg F was necessary to vaporize
any water from the oil. Prevention of liquid carry-over is
also essential to avoid water accumulation in the lube oil
system.
The compressor skids are equipped with standard process
and safety control devices to ensure safe and reliable
operation.
Results
Once the well candidates were obtained, a verification was
carried out ensure that the flowline size and configuration
would not choke the incremental production. Additional
consideration was given to the location of the wells, with
preference given to wells situated further from local
communities to avoid concerns around noise levels.
After determining the key parameters for the compressor
basic design such as the capacity and compression ratio,
compressor selection process began. It was an essential
requirement that the compressor packages had a small
footprint and were easily relocatable. They also had to be
capable of extended unmanned operation and have a high
operational reliability.
All factors having been considered, the final package
design consisted of a wet screw type compressor. This was
selected due to its high compression ratio (up to 9.25),
high reliability, and minimum maintenance requirement.
The chosen design was capable of delivering 0.5 – 1.0
MMscfd and contained a separator/scrubber sized to
handle 200 barrel/day of liquid production.
The simplified process diagram for the flooded wet screw
type compressor4 is shown in Figure 1. The compressor
Currently Vico has 19 wellhead compressor units installed
in the field compressing between 0.5 and 1.3 MMscfd per
unit. These are connected to wells producing from
reservoirs whose depths range from 8,000-ft to 13,000-ft,
with reservoir pressure varying from 1,000 psi to 300 psi.
Individual well incremental well production rates have
ranged from 0.2 MMscfd up to 0.4 MMscfd. The
operating cost has proved to be minimal, and fuel
consumption for each engine in the range of 0.02 MMscfd.
Regular optimization is carried out, and compressor skids
are relocated to different wells when appropriate.
Conclusion
The wellhead compressors have successfully lowered the
flowing tubing head pressure of low rate late life gas
wells, resulting in better well productivity and an
increased reserves recovery through extension of the well
life. The compressors sustain stable flow and have a low
operating cost. Plans are now in place for a wider
application of this technology throughout the Vico fields.
SPE 132855
References
1.
2.
3.
4.
Lee, J.; Wattenbarger, R. A., “Gas Reservoir
Engineering”, SPE Textbook Series Vol. 5 (1996)
Brown, Kermit E., The Technology of Artificial Lift
Method, Vol. 4, Petroleum Publishing Co. 1984.
Brown, K. E., and Lea. F.:”Nodal System Analysis of
Oil and Gas Wells”, JPT (Oct.1985) 1751.
Standard Compressor Package, “Operation &
Maintenance Manual Insert”, Toromont (2005)
3
Acknowledgements
The authors would like to thank the management of VICO
Indonesia and BP Migas for permission to publish this
paper.
Nomenclature
PSC:
Production Sharing Contract
OD :
Outside diameter
m :
metre (length)
4
SPE 132855
Figure 1: A simple diagram of Compression Process
Figure 1. VICO Indonesia (Sanga-Sanga PSC)
Compressor
Oil Separator
Suction Scrubber
Inlet
Aftercooler
Lube Oil Cooler
Lube Oil Filter
Drain
Discharge
Figure 2. A simple diagram of Compression Process
SPE 132855
5
Figure 3. Well head compressor
1.6
1.4
1.2
1
0.8
0.6
0.4
0.2
0
18
20
7 18
20
2 17
20
9 17
20
4 01 6
2
11 16
20
6 16
20
1 15
20
8 15
20
3 01 4
2
10 14
20
5 01 3
2
12 13
20
7 13
20
2 12
20
9 12
20
4 01 1
2
11 11
20
6 11
20
1 10
20
8 10
20
3 00 9
2
10 09
20
5 00 8
2
12 08
20
7
C o m p re s s e d G a s ( M M s c f d )
C-8200F Compression Performance
Actual w/ WHC
Plan w/ WHC
w/o WHC
Figure 4. Well Production performance