The Duri field, operated by Chevron under a production sharing contract with Government of Indonesia, is located in Riau province of central Sumatra about 120 km northwest of the city of Pekanbaru. The Duri Steamflood (DSF) Project is the largest Steamflood project in the world. Duri field was discovered in 1941 and start producing with primary production in 1958. Steamflood project started in 1985 and reached the peak production of 300,000 barrels oil per day later on late year 1994. Many well technologies have been applied, related to producer well completion and sand control, injector well completion, artificial lifts, and horizontal drilling to optimize the oil recovery. Heat management process was established to manage the steam injection efficiently. The DSF project was developed from Area-1 until Area-12 with different pattern sizes and configurations. The pattern sizes range from 5.5 acres to 15.5 acres. Pattern configurations vary and consist of 5-spot inverted 7-spot inverted and 9-spot inverted patterns. The DSF plans for further expansion to northern part of Duri field by developing new areas and other areas such as Duri "Ring", the area surrounding the existing producing field. Until 1998, steam was generated using oil as fuel but in year 2000, generators were converted to natural gas. The gas consumption reaches 414 MMscfd and mostly supplied from neighbored production sharing contractor ConocoPhillips using 28 inch x 530km pipeline transmission operated by 3rd party. On 29 September 2010, when DSF was producing 190,000 barrels oil per day, a failure event occurred that resulted in a release of gas from the pipeline. The accident cut the gas supply to DSF, caused the shutdown of steam generation facilities, and forced the world’s largest steamflood project to shut some of the producer wells for several days. This incident was the first "no-steam" incident to Duri steamflood project operation. The impact was severe. Production dropped to 58,000 barrel oil per day, and gradually increased back after the gas supply was ramped-up to normal levels. The gas supply was ramped-up and back to normal in 25 days. The production ramped-up, reached the peak slightly lower than before the event and production is continuing to recover with different mode where the decline is lower than before the incident. After the initial incident, there were other events, related to gas supply issues and interruptions of steam supply from cogeneration plant (COGEN) that have negatively impacted the production recovery. This paper shows the on-going massive efforts of Chevron and Government of Indonesia to bring the world’s largest steamflood project to full recovery and sustainably rejuvenate the Duri Field production.

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Distillation of oil at the steam-oil interface has long been recognized as an important mechanism for oil recovery during steam flooding, particularly in light-oil reservoirs. However, the heat and mass transfer mechanisms at the interface are not well understood. This paper describes an experimental study conducted to shed more light on these mechanisms. The apparatus used consisted of a vertical sand pack containing a three-component liquid mixture, namely, cyclohexane, n-octane, and water. Cyclohexane has a boiling point lower than that of the steam introduced at the top of the sand pack, so that this hydrocarbon component will be predominantly distilled off. Data obtained included produced hydrocarbon and water volumes, sand-pack temperature profiles, and steam front velocity as measured with the aid of the CT scanner. Analysis of the data indicates that, contrary to the usual assumption, steam distillation does not occur at equilibrium conditions. Moreover, oil recovery by steam distillation is largely dependent on the steam saturation point and injection rate. Based on these findings, an analytical steam displacement model has been developed. Temperature profile, steam front velocity, and hydrocarbon production based on the model agree satisfactorily with the experimental results.

Carbonate rocks have been placed in emphasis for several studies in Indonesia because it is almost covering 60% of production basins in Indonesia; on the other hand, the fractured carbonate zones formed important oil and gas reservoirs. Those reservoir qualities were able to pronounce the sustainability of Indonesia's production for some period of time. Unfortunately, the heterogeneity of carbonate fractured reservoir widely known as the most unpredicted production performances. In Indonesia oil and gas upstream activities, it is often overlook when deal with the development scenario of carbonate field, furthermore to carbonate fractured reservoir. In fact of those, some lesson learn gained from previous approach of reservoir judgment was able to guide in how to better manage the development of those fields in Indonesia.Regional to detailed technical related aspect to develop carbonate fractured reservoir; involving Geology, Geophysics, Reservoir and Production (GGRP), are the primary important to be considered in order to gain understanding of the uncertainties from heterogeneities of those rock. History of carbonate rock environment depositional system in Indonesia is alongside with equatorial line throughout the geological time scale makes the location beneath Indonesia archipelago comprising with carbonate rock. The native characteristic of Indonesia archipelago became more complex by the support of subduction zone along the region. These complexities of geological condition create opportunities for upstream activities to develop those reservoirs, especially in East Java throughout Bali area.The initiation to optimizing the production on named area was conduct by integration of reservoir management using a guideline from previous overlook result, without creating pessimistic impression. Seismic relative amplitude processing was deliver to appropriate attribute, supported by geological data from well and each test. Analogy of data was not being used as a prominent data, but rather than a validation of methodology approaches, especially for petrophysics and modeling input. Petrophysics evaluation carried in this study uses an approach of fractured rock rather than possible interconnecting vuggy porosity. The relationship between matrix permeability and fracture permeability was modeled in dual porosity/permeability model; which supported the conclusion to geological condition of carbonate fractured reservoir in the area.

Enhanced Oil Recovery (EOR) is a tertiary recovery which requires relatively a high cost of CAPEX and OPEX. The current EOR technique is generally stand alone and injected into single reservoir layer without contributing to the other layers (unconnected reservoir layer). For this reason, a breakthrough of low cost EOR technology (CAPEX & OPEX) is needed, especially since oil prices tend to fall low. Vibroseismic EOR is one of the EOR methods (categorized as mechanical EOR) that is inexpensive, fast response / yield, high mobility (can be moved to another place), environmentally friendly, and could be combined with the waterflood method or other EOR methods to get more effective and optimal result. However, the research & implementation on Vibroseismic EOR are still limited. The paper describes the pilot test of Vibroseismic EOR technology in Tempino Field. The initial stage is to select the suitable field for implementation Vibroseismic EOR. Then, the rock & fluid properties of the selected field are tested and examined by vibration and stimulation in the laboratory to obtain optimum frequency of 20 Hz S waves (circular / transverse) and 35 Hz P waves (longitudinal). The field scale-up process is carried out by measuring or testing field parameters called Vibroseis Field Parameter Test (VFP Test). VFP Test results get the optimum frequency of S and P waves of 20 Hz using 3 trucks and drive level 70% with amplitude value up to 0.024 rms (root mean square). Through the EOR vibroseismic method, the truck is the source of vibrations on the surface will generate acoustic waves propagating through the rock (subsurface) throughout the reservoir layer within the wave penetration range, generally reaching a depth of 6500 ft depending on the amplitude / power source of vibration, thickness of weathered layer, and rock type. The waves that reach the reservoir will affect the rock & fluids properties. The pilot test results on production wells showed a positive response within 1 month after vibration, especially those around the existing injection wells which the permeability was relatively good. The increased production accumulative of 10 (ten) monitoring production wells about 8% and withhold declining rate up to 20% from base case. Oil drainage around production wells and drainage direction are confirmed by changes in hydrocarbon saturation maps through passive seismic techniques measured before, during, and after vibration. The results of this pilot test show that Vibroseismic EOR technology is very promising to be developed to the full-scale stage and implemented in other areas.