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Andrianata S.,VICO | Susanto A.,VICO
Society of Petroleum Engineers - SPE/IATMI Asia Pacific Oil and Gas Conference and Exhibition, APOGCE 2015 | Year: 2015

Depletion of the reservoirs leads to a decrease in field production rate. Wells production rate continue to drop below the minimum critical velocity, at which point the liquid that was previously carried upward by the gas begins to fall back. The produced liquid accumulates in the well creating a static column of liquid, therefore creating a backpressure against formation pressure and reducing production until the well ceases production. Down hole Capillary Surfactant Injection (DCSI) is installed on the wells to overcome the liquid loading symptom by generating foam, thereby reducing the surface tension, lowering the fluid density, and lowering critical rate. This paper discusses the improvement to obtain higher success ratio of DCSI installation project on the observed field. Analysis and improvement is done to improve the success of DCSI installation through a comprehensive wells screening, continuity laboratory test, and field optimisation. The screening including the selection of liquid loaded wells & laboratory test (foam test, pH, and salinity test) were corrected with the actual temperature to obtain an accurate foam performance. Correlation is generated to correct the effect of foam build rate and decay rate against critical parameters. Validating well performances with the results of laboratory tests is conducted by continuously field optimisation. The laboratory test is significantly important to screen DCSI well candidate. Surfactant concentration, temperature, & condensate content are critical variables for foam build up and decay performances. Uncertainty variable and un-matching well performance previously not assessed can be reduced by these improvement steps, thus increasing the success ratio DCSI project. The improvement DCSI screening proposed is used as a reference to start the DCSI project to obtain higher success ratio. Copyright 2015, Society of Petroleum Engineers. Source

Weatherall G.,VICO | Halinda D.,VICO | Daungkaew S.,Schlumberger | Suriyanto O.,Schlumberger | And 2 more authors.
Proceedings of the Annual Offshore Technology Conference | Year: 2014

The coal bed methane (CBM) fields often showed wide variety of productivity ranges. Some wells were also drilled for both the CBM and the conventional oil & gas resources, hence adding the complexity of the well completion design. While designing for the optimal completion for both types of resources, the bounding shale layers properties become critical, especially when the coal layers are with lower permeability range and are to be fractured before production. The fracture treatment needs to be designed to be contained within the targeted zone, without bypassing the shale into the other layers (such as the water bearing sand). This is when the shale stress testing plays important role in providing the shale layers' stress parameters. The shale stress testing can be conducted with the dual packer module, which is part of Wireline Formation Tester (WFT) string. The tested shale zone is isolated with both packer elements, which is inflated with the wellbore fluid to create the isolation / sealing from the other zones. After packer inflation, the tested shale was injected with the wellbore fluid, or with fresh water specially carried down hole with the fluid chambers. The whole injection process is made efficient with the downhole pump module and the wireline cable conveyance, and multiple zones can be tested in one descent. After the injection, the pressure is allowed to fall off while the pressure and pressure derivative profiles are monitored. The data sets from two shale stress testing stations are presented as the case examples. The analysis of the data utilized the G-function plot, as well as square-root time plot. The output of the analysis included mainly initial breakdown pressure, closure pressure, fracture propagation pressure, and initial shut-in pressure. Permeability information could be extracted if the fall-off analysis showed clear radial flow regime. In one station, multiple cycles of injection - fall off process can be conducted to obtain better representative of the data sets. A reconciliation plot from all cycles in one station was then built to analyze the stress parameters. In larger scale, the measured parameters could be integrated into geomechanics study. Copyright 2014, Offshore Technology Conference. Source

Suhendar A.D.,VICO | Kurniawan R.,VICO | Lizcano E.,VICO
Society of Petroleum Engineers - International Petroleum Technology Conference 2013, IPTC 2013: Challenging Technology and Economic Limits to Meet the Global Energy Demand | Year: 2013

VICO Indonesia operates the Sanga Sanga PSC in East Kalimantan which is on production since 1972. Reservoirs are mostly gas and depleted. Very Low Pressure compression "VLP" systems, which operate at 15-25 psig suction, are widely installed across all fields. As a result, flowing tubing head pressures in a large number of wells are in the order of 40 psi. Completion tubing sizes range from 2 3/8" to 4.5" with the majority being 3.5". Despite this, a large proportion of VICO's existing gas wells are subject to liquid loading, leading to premature abandonment of producing zones when the gas velocity in the tubing is lower than the critical velocity. This phenomenon is influenced by the tubing size, surface pressure and the amount of associated liquids produced with the gas. Historically, some temporary activities were carried out to overcome this problem. This included the reactivation of wells by flowing to flare and/or dropping foaming agents. The result of this type of "temporary" application was very variable and inconsistent. In an effort to continuously optimize the system and reduce the abandonment pressures, a large scope deliquification project was launched in 2006. The project included the application of capillary strings for down-hole chemical injection, plunger lifts, and wellhead compressors. This program was applied across all fields in VICO. The results were very positive in bringing back the production strings previously considered marginal or not producing. The field wide implementation program for both capillary string units and well head compressors was conceived to allow periodic relocation and optimization of the units and the system. As a result, all these deliquification techniques have now become a core element of the Base Production System. They continue to be optimized on a day to day basis and as a whole they are responsible for approximately 10% of the total production from VICO. Source

Wijanarko A.,VICO | Rylance M.,British Petroleum | Pizzolante I.,ENI S.p.A | Hazman,VICO | Dharma B.,VICO
Society of Petroleum Engineers - SPE Asia Pacific Oil and Gas Conference and Exhibition 2010, APOGCE 2010 | Year: 2010

VICO Indonesia is the operator of the Sanga-Sanga Production Sharing Contract; located onshore of the Mahakam delta, in East Kalimantan, Indonesia. Since inception the PSC has produced over 70% of the estimated original gas in place. The fields are relatively mature with most of the remaining gas resources locked up within the lower permeability reservoirs, where conventional tight-gas completion approaches have not been very effective in ensuring depletion of the resource. A valuable prize of at least 0.5 TCF would be readily achievable, if these lower permeability resources could successfully be developed and recovered. The lower permeability formations being referred to; are typically sub milli-darcy, and the ability to achieve any kind of sustainable economic production rate has been extremely problematic. Previous attempts at hydraulic fracturing within VICO, over nearly three decades, have been dramatically ineffective and have rarely enjoyed any sustained production improvement at all. Geologically the reservoirs are best described as distributary river channels, in a lower deltaic plain environment and therefore these individual sands can vary in size and connectivity quite substantially. Alternative technologies, such as horizontal drilling are being applied, but only within those sand bodies which are larger and which can therefore readily support the economics associated with horizontal well drilling. In 2006 a detailed technical review of the previous 30 Years of hydraulic fracturing operations was commissioned, this review noted that there were five basic 'skins', which were causing problems for hydraulic fracturing. These 'skins' were: wellbore integrity, execution QA/QC, relative-permeability, regional tectonics and poro-elasticity. The data was extremely convincing and based upon the review a decision was made to implement a five well pilot in order to confirm the findings and present solutions. This paper will describe the long and difficult journey of VICO hydraulic fracturing, from the original treatments through the recent review, the fracturing pilot from 2007-2009 and into the early stages of the new fracturing campaign planned for 2010-2012, The paper will present the results of the detailed study, the implementation phase of the pilot and the forward plan for the VICO low permeability zone(s) based upon the significant progress, successes and deliverables of the fracturing pilot in the Nilam G-Sands. Copyright 2010, Society of Petroleum Engineers. Source

Hermawaty I.,VICO | Permana R.,VICO | Silitonga F.,British Petroleum | Wijanarko A.,VICO | Soenoro A.,VICO
Society of Petroleum Engineers - International Petroleum Technology Conference 2013, IPTC 2013: Challenging Technology and Economic Limits to Meet the Global Energy Demand | Year: 2013

VICO Indonesia is the operator of Sanga Sanga Production Sharing Contract (PSC) area in the onshore Mahakam Delta, East Kalimantan, Indonesia since 1968. Over 40 years, the PSC has produced more than 12 TSCF of gas through more than 800 wells to feed the Bontang LNG Plant and domestic market. One of the major fields in the contract area is the Badak Field, which has contributed more than 6 TSCF of gas production. Badak Field's reservoirs are the analog of the present day's Mahakam delta, and comprise of stacked distributary channel sands deposited in the deltaic environment draping on a four-way dip closure anticline. The shallower stratigraphic interval is dominated by fair to good quality upper delta plain, amalgamated channel sands, with a combination of water and depletion drive mechanism. The deeper stratigraphic intervals are dominated by fair to poor quality lower delta plain, more isolated distributary channel sands and mouth bar. The main reservoir drive mechanism is depletion drive. As the early development strategy of the Badak Field had been focused mainly on drilling the best reservoirs, those shallow reservoirs in the crestal area, the majority of these reservoirs are now depleted. In contrast, low permeability deeper reservoirs with relatively higher reservoir pressure, still contain significant remaining resources. VICO's depletion challenge is to balance between increasing the recovery from the deeper intervals, whilst continue optimizing the recovery from shallow intervals. An Integrated subsurface study has been conducted to understand the geological description of the reservoirs, ultimately to unlock the reserves of the deeper low permeability intervals. Several development options have been carefully evaluated, which lead to the implementation of new technologies to optimize recovery, including cluster wells, horizontal wells, and hydraulic fracturing. The results of the implementation of the development strategy and technology have been outstanding. This has helped sustain the Badak Field's decline rate at around 25% annually compared to a 45% natural decline. In 2011, the gas production was successfully maintained at 75 MMSCFD or 3 times the base line of the "do nothing" case prediction, with more than 55 BSCF of reserves progressed. This paper describes the successful implementation of integrated development study, which proved to be an effective process to ensure optimum reservoir management of low perm reservoirs of a mature asset. Copyright © (2013) by the Society of Petroleum Engineers. Source

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