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Agee D.,Schlumberger | Yudho A.,Schlumberger | Schafer L.,Schlumberger | Wijanarko A.,VICO Indonesia
Proceedings - SPE International Symposium on Formation Damage Control | Year: 2010

The fields of East Kalimantan, Indonesia contain several depleted gas zones of medium permeability (0.1 to 300 mD). Though the permeability is quite good for gas bearing formations, the majority of the wells targeting these sands have failed to produce at expected rates. In the 1980s, hydraulic fracturing was introduced to the area in an attempt to increase production. The treatments yielded limited success with many wells actually producing less after being fractured. This led operators in the area to believe that the formations could be water sensitive with damage from the injected fluids causing the poor results after fracturing. As laboratory testing has ruled out water-sensitive mineralogy, the suspected cause of damage has been attributed to a decrease in relative permeability to gas after the fracturing fluid has penetrated the pore throats (water block). The water block conclusion is supported by the low percentage of injected fluids that are returned after the treatment. In 2007, VICO performed four fracturing treatments using a conventional surfactant to aid in post-frac cleanup. Only 2 of the 4 wells that were fractured produced after the treatment. Again, a common problem between the wells was the poor return of treatment fluids during cleanout. The limited success of these treatments indicated the water block issue had not been resolved. After reviewing the results of the first four wells, three additional fracturing treatments were placed in similar reservoirs using a microemulsion additive instead of the surfactant. Though laboratory testing in cores between 1 and 8.5mD failed to show a significant difference between the microemulsion and surfactant, the wells fractured with the microemulsion additive consistently outperformed those fractured previously in terms of returned treatment fluids and incremental production. Paktinat et al. (2006) wrote that the use of fracturing fluids with microemulsion in unconventional tight gas reservoirs can help increase production by increasing the relative permeability to gas in the area surrounding the fracture. Our study shows that similar benefits can also be achieved in depleted gas reservoirs with permeabilities greater than 1 mD, even if the benefits can not be clearly demonstrated under laboratory conditions. Copyright 2010, Society of Petroleum Engineers. Source

Jauhari U.,Slamet ST | Anggraini D.A.,VICO Indonesia | Sinaga I.B.,VICO Indonesia | Widiastuti B.,VICO Indonesia
Society of Petroleum Engineers - SPE Asia Pacific Oil and Gas Conference and Exhibition 2011 | Year: 2011

The Semberah field is one of the main oil and gas producing areas operated by VICO Indonesia in East Kalimantan, Indonesia. Production from this field has been focused mostly from shallow-level reservoir (C-I intervals). After production of more than 30 years, the shallow and high-permeability intervals are currently highly depleted. Meanwhile, deep and low-permeability reservoirs (J level) have rarely been penetrated leaving significant reserves. Accessing these reserves is a highly challenging work today. A recent well was drilled to access the reserves in a J sand but the drilling had to be stopped earlier due to total loss of circulation whilst penetrating a shallow high-permeability and highly depleted sandstone I082A. An integrated pore pressure prediction approach has been carried out during the planning of drilling and completion of a proposed S86 well. The objective was to successfully access deep target reserves in the J sandstone by safely drilling through the highly-depleted I082A sandstone. The approach integrated available data including well logs, cores, formation pressure, historical-match derived pressures, and drilling parameters. Pore pressure prediction showed that the proposed S86 well would penetrate normal pressure regime (8.45 ppg) to -8,500' SS. Within this interval, variously depleted reservoirs (3-6 ppg) would be penetrated. Starting from -8,500' SS to -10,680' (TD), the well was predicted to enter overpressure environment (8.45-13 ppg). Within the environment, a higly depleted I082A with 500 psi (0.87 ppg) was estimated to be encountered at -8,819' SS. The pore pressure prediction study recommended 1) to drill with normal mudweight of 10-12 ppg and set 9-5/8'' casing point before penetrating I082A sandstone, 2) to drill through I082A to its bottom with low mudweight (8-9 ppg) and isolate with 7'' short liner, 3) drill 6'' open-hole to TD with high mudweight (12-13 ppg). The newly proposed well safely drilled through the highly depleted I082A sandstone and access to the reserves in the targeted J sandstone was successfully achieved. This great success has opened up an opportunity for further development drilling in the Semberah field. Copyright 2011, Society of Petroleum Engineers. Source

Wijanarko A.,VICO Indonesia | Ismanto B.,VICO Indonesia | Permana R.,VICO Indonesia | Pizzolante I.,ENI S.p.A
Society of Petroleum Engineers - SPE Asia Pacific Oil and Gas Conference and Exhibition 2012, APOGCE 2012 | Year: 2012

VICO Indonesia is the operator of the Sanga-Sanga Production Sharing Contract located onshore of the Mahakam delta, East Kalimantan, Indonesia since 1968. Over 40 years the PSC has produced 70% of the estimated original gas in place, supporting Bontang LNG plant. VICO has 7 producing fields, in a complex fluvial deltaic deposition with more than 2700 gas and oil reservoir, mixed of depletion and water drive mechanism reservoir. VICO production peaked at 1.5 BSCFD in 1995 then start to decline. Current production is in the range 385 MMSCFD of gas and 14500 BOPD of liquids from 400 active wells. In a situation of 46% annual base decline, to fulfill domestic and LNG contractual commitments and to optimize reserve recovery, VICO generated and implemented an integrated and aggressive work program called "Renewal Plan". This is an integrated approach between reservoir management and technology application; it provides a detail road map to onward development strategy. The main elements of the plan are extensive development drilling activities (conventional drilling, grid base drilling, cluster well drilling), low permeability reservoir optimization (horizontal well, hydraulic fracturing, radial drilling), production optimization (deliquification technique, permanent coil tubing gas lift for monobore type) and facilities optimization (reducing abandonment pressure by additional compression installation, wellhead compressor, debottlenecking). Technology application in drilling, completions, production and facilities optimization combine with synergy from multidisciplinary team have resulted in maintaining VICO production decline in the range of 5% (vs 46% base decline), allowing promoting and partially replacing the reserves at an attractive development cost, even after 40 years production life. This paper will describe the successful implementation of renewal plan in VICO Indonesia, which proved to be an efficient example of better reservoir management for optimum development of mature assets. Copyright 2012, Society of Petroleum Engineers. Source

Kramadibrata A.T.,VICO Indonesia | Sumaryanto,VICO Indonesia | Panjaitan P.,VICO Indonesia
Society of Petroleum Engineers - SPE Asia Pacific Oil and Gas Conference and Exhibition 2011 | Year: 2011

VICO Indonesia has operated the Sanga-Sanga PSC in East Kalimantan, Indonesia, since 1968. More than 750 development wells have been drilled to date in the complex Mahakam Delta in East Kalimantan. The mature reservoirs are predominantly gas, extremely depleted and have an average recovery factor of about 70%. To optimize the development cost VICO changed the completion from multi string and multi packers to monobore in 1997 and furthermore to dual monobore in 2005. VICO has also focus to optimize oil production and recovery. The current oil recovery factor is relatively modest and needing further detail study and optimization. A multi-disciplinary team was performed to further evaluate oil potential in all VICO fields including review of historical performance, geology and development opportunities. These reservoirs were also evaluated using material balance to understand the initial volumes in place, the drive mechanism and the opportunity to maximize production and oil recovery through the existing wells. One of the challenges in maximizing oil recovery is artificial lift system in monobore completion. VICO has evaluated and selected gas lift as optimum artificial lift method. There are two possibilities to gas lift oil wells (1) using a side pocket mandrel in the conventional dual string completion and (2) inject gas lift through coil tubing in the monobore completion. The paper describes innovative gas lift system in monobore completion where gas lift mandrels were not pre-installed. This technique has been implemented, by running 1.5″ coil tubing into a well through a special tubing hanger attached to the top of the Christmas tree. This technique allows gas lift to an oil reservoir in monobore well completion without requiring rig for recompletion. This application is known as "Permanent Coil Tubing Gas Lift" or PCTGL. This technique has been implemented in "MUT-X" well that was not capable to flow naturally, and then PCTGL was installed to resume oil production. The well was flowing 600 BOPD initially and now is continue flowing at 350 BOPD. In summary, PCTGL is a proven favorable and simple method for artificial lift application in monobore completion to maximize oil production and recovery. Furthermore, this technique has helped VICO in synergizing gas and oil development to maximize value of the assets. Copyright 2011, Society of Petroleum Engineers. Source

Priambudi A.,VICO Indonesia | Baraba R.N.,VICO Indonesia | Tranggono N.W.,VICO Indonesia | Aryanto B.,VICO Indonesia
Society of Petroleum Engineers - International Petroleum Technology Conference 2012, IPTC 2012 | Year: 2012

The Badak Export Manifold (BEM) is a complex manifold to gather the entire gas delivery from upstream fields and to deliver hydrocarbons to Liquefied Natural Gas (LNG) plant and to domestic commercial sites, manufacturing fertilizers and chemicals. Besides the function as gas processing facilities, the duties of the export manifold are to maintain pressure, distribute gas flow, implement off take logic during shut down and coordinate gas delivery. The BEM is the beginning of four main pipelines work in parallel configuration to allow flexibility of the gas delivery and to maintain gas composition within acceptable specification. The pressure stability and gas specification are the important aspect of the export manifold operations. These operations become challenging tasks because of the changing of the upstream fields' condition. The pressure was decreased and the gas composition became richer, not to mention gas supply was less than gas demand as well as pipelines capacity. A quick decision and field action should be taken immediately to avoid plant shut down and gas composition out of consumers' specification. In addition to gas composition become richer, hilly terrains of the pipelines create liquid hold up (LHU) in the pipelines. The LHU will increase the back pressure to upstream field, and as consequences the plant with natural gas flow from well will be restricted. Despite the flexibility of the supply, the parallel operations of the pipelines make gas flow tend to go to the line which has less back pressure. The BEM takes an important part in the attempt to sweep liquid in the parallel mode by segregating gas flow into particular pipeline. Many efforts have been performed to improve export manifold operations. It was included establishing a clear operation guideline during normal and emergency situations, adjusting operations parameter to minimize unnecessary shut down, and installing additional equipment to allow remote operations of safety equipments within export manifold area. Nowadays, almost all of the BEM parameters can be monitored remotely to support better operation. Copyright 2011, International Petroleum Technology Conference. Source

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