Aslam, B. M. (Institut Teknologi Bandung) | Ulitha, D. (Institut Teknologi Bandung) | Swadesi, B. (Institut Teknologi Bandung) | Fauzi, I. (Institut Teknologi Bandung) | Marhaendrajana, T. (Institut Teknologi Bandung) | Purba, F. I. (Pertamina EP) | Wardhana, A. I. (Pertamina EP) | Buhari, A. (Pertamina EP) | Hakim, R. (Pertamina EP) | Hasibuan, R. (Pertamina EP)
Tanjung Field is a brown field which pressure has already depleted and been supported by waterflooding for over a decade. To improve production, surfactant injection, is being studied to be employed in the field. The main objective of this study is to identify parameters that affect oil production increase. History match of the pilot test was carried out to improve the reliability of the reservoir model, hence improving the prediction result of surfactant injection forecast.
History match of the pilot test has been carried out using CMG STARS commercial simulator by considering mechanism inferred from laboratory evaluation such as wettability alteration, surfactant retention, interfacial tension reduction and improvement of mobility control due to lower oil-surfactant emulsion viscosity. These parameters are initially perceived from laboratory result, upscaling and adjustment is applied to field model to further on do sensitivity study. Sensitivity analysis of every parameter is provided to better understand the effect of each mechanism that contributes to the oil incremental result.
Stratigraphically, Tanjung Structure has 7 productive zones: Zone A, B, C, D, E, F and P. Reservoir Zone A has total estimated reserve of 193,732 MMSTB, with recovery factor of 16.3%. The zone consists of conglomerate sandstones with porosity of 21% and permeability ranging from 10 to 100 mD. The field produces light oil within 40 °API, 30% wax content and 1.14 cP of viscosity. T-119 is the well chosen to be injected due to its structural position that ease flow by gravity force to producer wells.
Forecast simulation based on coreflood result has been conducted for pilot test. However, the result was very pessimistic in predicting incremental oil gain and breakthrough time after compared to pilot result. An attempt to history match the surfactant flood pilot is presented by considering phenomena that is not included in the forecast based on additional lab and field data.
Bachtiar, A. W. (PT. Pertamina EP) | Purba, F. I. (PT. Pertamina EP) | Dusyanto, E. D. (PT. Pertamina EP) | Mucharam, L. (Institut Teknologi Bandung) | Swadesi, B. (Institut Teknologi Bandung) | Santoso, R. K. (Institut Teknologi Bandung) | Fauzi, I. (Institut Teknologi Bandung) | Hidayat, M. (Institut Teknologi Bandung) | Aslam, B. M. (Institut Teknologi Bandung) | Dzulkhairi, H. (Institut Teknologi Bandung) | Surya, A. (Institut Teknologi Bandung) | Marhaendrajana, T. (Institut Teknologi Bandung)
Injectivity is a critical issue in polymer injection since it determines the success of polymer to displace and sweep oil in the reservoir. Polymer has shear rate and temperature-dependence viscosity which is substantially different behaviorfrom water. Any calculation related to injection performance should consider this behavior. Injector should be organized to achieve the desired injection rate without any issue. The easiest approach to design the optimum injector is using IPR-TPR method. Therefore, in this paper, we develop Non-Newtonian IPR-TPR method to achieve optimum completion design of injector. The IPR equation is built using modified Darcy equation for Non-Newtonian fluid. The TPR equation is developed using
We used case study of T-048 – T-012 injector-producer in Tanjung Field Zone-C, Indonesia with 500 and 2,000 ppm HPAM polymer. Simulation results show that there exists changing process from shear thinning to Newtonian along the tubing because of temperature and injection velocity while only Newtonian behavior occurs in near wellbore for 500 ppm injection case. Smaller tubing OD produces higher effective injection rate than the bigger one. The 2,000 ppm polymer cannot enter the reservoir due to bottomhole pressure reaches the fracture presure.Finally, smaller tubing OD (below 2.875 in) is suitable in Tanjung Field Zone-C for 500 ppm polymer injection. 2,000 ppm polymer cannot be deployed and needed further evaluation.
Tuesday, October 17 GP01 Opening Session Pecatu Halls 3 & 5 GP02 Executive Plenary Session: Energy Resilience through Efficiency, Collaboration and Technology Pecatu Halls 3 & 5 Moderator(s) Craig Douglas Stewart - PT. Medco Energi Internasional Speaker(s) Javier Rielo - Total E&P Asia Pacific, Christina Verchere - BP, Visal Leng - GE Oil & Gas Our industry has had to persevere a significant downturn over the last several years due to the drastic drop in oil and gas prices. To survive and thrive in this dynamic environment, and to continue to provide energy to our many stakeholders, the industry has had to transform itself and will need to continue to do so. This has and will need to be achieved through improved efficiency to create a sustainable operational blueprint, employing new strategies for collaboration between operators and the service sector and leveraging innovative technologies. This Executive Plenary Session brings together an esteemed group of industry players, representing the perspectives of National Oil Companies, International Oil Companies and major Service Companies, to discuss the achievements and outlook on this journey to energy resilience. Oil price have declined sharply since 2014.
An increasing percentage of worldwide hydrocarbon production is being achieved from mature fields, as new discoveries prove elusive and technically challenging to bring to market. In this environment, robust and efficient enhanced recovery from these mature assets will play an increasingly important role in production operations. Often used as an initial completion approach or selective remedial stimulation method, hydraulic fracturing is increasingly applied as the method of choice to bolster and improve such declining fields to restore and maintain higher production levels.
Hydraulic fracturing is finding increasing application as a widespread approach to mature field redevelopment. This paper will explore the various factors that should be considered when proposing hydraulic fracturing for this purpose, given the very specific nature and condition of mature fields.
Techniques that can be applied to determine various aspects of mature field fracturing operations will be discussed, together with approaches related to all areas of fracturing implementation; this will provide the reader with an ability to perform a first-pass assessment of the pros and cons of various approaches. In addition, there will be significant discussion related to the potential pitfalls associated with ill-prepared and inappropriate campaigns.
Case histories will provided examples of mature field redevelopment utilising hydraulic fracturing as the principal approach. Candidate selection and pre- and post-frac production behaviour will be discussed, together with the lessons learned and improvements realised during the execution of these programmes.
It was not very long ago, in fact as late as 1990, that many engineers considered fracturing as applicable exclusively within the realms of low- to very low-permeability reservoirs. It is still absolutely true that fracturing remains the only technique that can render low-permeability formations economic. However, it is unfortunate that some continue to believe this is its exclusive application and remain unaware of major new developments over the last two decades that make fracturing compelling for almost any reservoir. For many others, fracturing remains an option of last resort, if everything else fails, let's try fracturing.
There have been three major reasons for occasional reluctance to consider this technique. The first of these is the "effective cost?? of fracturing, especially when performed on an ad-hoc basis, one job at a time, assigning all mobilization and set-up costs to a single treatment; such a situation is both undesirable and untenable. The second is an unreasonable phobia that fracturing generally increases water production, a manageable situation for an industry accustomed to dealing with produced water. Finally, the third reason is that fracturing treatments can be complex, sensitive, serial operations and require skill sets and equipment that are not easily created or replicated in a new environment.
All too often, in areas where fracturing has not been employed in the past, it is tried for the first time on a very bad and/or on an underperforming well. One recollection is that a production manager of a company, having been pressured by upper management to acquiesce to fracturing, provided a candidate well for the treatment that was some 25 years old and already producing at a 99% water cut. Presumably, the logic of this choice was that if fracturing is such a good approach to production enhancement, it should be capable of also turning water into oil. Another frequently encountered problem is that people try to assess the appropriateness of fracturing based on the results from a single well. Fracturing is complex: Many things can happen or situations arise, and any negative results may affect adversely the potential for future deployment of this widely established well completion and stimulation operation in a particular petroleum province.
The evolution of the Tip Screen-Out (TSO) technique in the late 1980s (Martins et al., 1992) and its subsequent application have essentially rendered every well a potential candidate. Consider this: It would take more than 400 gas wells in a reservoir with 0.01 md permeability, with massive hydraulic fracture treatments, to equal the incremental performance of just one correctly designed and successfully fractured well in a 10-md reservoir.
In the design of hydraulic fractures, it is necessary to make simplifying assumptions. Fifty years ago, our industry was mathematically obliged to describe fractures as simple, planar structures when attempting to predict fracture geometry and optimize treatments. Although computing tools have improved, as an industry we remain incapable of fully describing the complexity of the fracture, reservoir, and fluid flow regimes. Generally, we make some or all of the following assumptions:
- Simple, planar, bi-wing fractures
- Completely vertical fractures with perfect connection to the wellbore
- Flow capacity that is reasonably described by published conductivity data
- Predictable fracture width providing dependable hydraulic continuity (lateral and vertical continuity)
To forecast production from these fractures, we frequently make the additional assumptions:
- Reservoir is laterally homogeneous
- Modest/no barriers to vertical flow in formation (simplified description of layering compared to reality)
However, we must recognize that all of these assumptions are imperfect. This paper will investigate the evidence suggesting that fractures are often subject to:
- Complicated flow regimes
- Complicated geometry
- Irregular frac faces
- Imperfect proppant distribution
- Imperfect hydraulic continuity
- Imperfect wellbore-to-fracture connection
- Residual gel damage, possibly including complete plugging or fracture occlusion
Additionally, reservoirs are known to contain flow barriers that amplify the need for fractures to provide hydraulic continuity in both vertical and lateral extent.
The paper appendix tabulates the results from more than 200 published field studies in which fracture design was altered to improve production. Frequently the field results cannot be explained with our simplistic assumptions. This paper will list the design changes successfully implemented to accommodate real-world complexities that are not described in simplistic models or conventional rules of thumb. Field examples from a variety of reservoir and completion types [tight gas, modest perm oil, coalbed methane, low rate shallow gas, annular gravel packs] will be provided to demonstrate where the field results differ from expectations, and what adjustments are necessary to history-match the results.
This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 86929, "Transportation of High-Pour-Point Oil Through Long Hilly-Terrain Pipeline, A Case Study in Kalimantan, Indonesia," by Satya A. Putra, SPE, and Edo Waspodo, SPE, Pertamina, prepared for the 2004 SPE International Thermal Operations and Heavy Oil Symposium and Western Regional Meeting, Bakersfield, California, 16-18 March.
This paper will detail how a mature oil field in the South Kalimantan region of Indonesia was revitalised by the use of hydraulic fracturing. The Tanjung Raya field is a complex, multilayered, mature oil field. This field was initially developed in the 1960's, with production peaking at over 55,000 bopd. By the mid 1990's, production had declined to less than 1,200 bopd. The introduction of a water flood increased production to a peak of 10,000 bopd, but this quickly declined at an average rate of circa 33% per year. With the introduction of a fracturing programme, based on treating existing and new wells, production has been maintained at a flat 7,000 bopd over the past two years. The hydraulic fracturing program has accounted for 80% of these significant production gains, adding more than 5.7 million barrels of recoverable reserves and extending the economic life of the field by more than 2.5 years.
Hydraulic fracturing is a process that is relatively underutilised in the Asia-Pacific region, as compared to North America, Latin America and the Middle East. With a couple of recent noticeable exceptions, the technique is either not considered during field development and redevelopment, or it is used on a one-off, remedial basis. However, fracturing can be an integral part of well design, and an effective tool when the technique is applied systematically by practitioners who understand its capabilities; as demonstrated in the Tanjung Raya field.
This paper will discuss how a significant increase in oil productivity from a mature field was attained with a very high propped fracture treatment success rate. It will also detail how the correct design of fracture treatments can enhance reservoir recovery rates, and fully utilise vertical wells as a low cost, effective alternative to horizontal wells, or to increase well spacing. The paper will also discuss the most significant issues of implementing such a program and how these issues were effectively dealt with in the Tanjung field.
Characteristic of high pour point oil may cause problems in pipelinetransportation if it is not handled carefully, especially in long and hillyterrain pipeline. It may form solid in ambient temperature, and further maycause pipe plugging along the line, especially in sloping pipe area. Thepipeline is 20 inch diameter stretch 250 km from Tanjung oil field to oilrefinery in Balikpapan, East Kalimantan Province of Indonesia.
Alternatives of transportation had been considered, such as insulation line,heating, chemical, etc. Alternative chosen was transportation of mix fluid ofthe high pour point oil and water. Transportation of mix liquid may preventaccumulation of solid oil particle at places along the line and avoid pipeplugging, and the method was also considered low cost of investment andoperation. Such method of transportation has been conducted since 1963 andreached peak pumping of 44.000 BOPD oil production. At present time total oilproduction has declined to only 7800 BOPD, and transportation of the oilproduction is conducted periodically 12 times a year in oil-water mixture of65% oil and 35% water, with total oil transported 250.000 Barrel per-pumpingperiod.
On year 2002 it was experienced an operational failure, when the pipelinewas plugged caused by solid oil particle accumulation, causing interruption ofpumping. An effort to remove the plugging has succeeded by conducting "rocking"method and injection of light oil, and such method was able to bringtransportation to normal operation in considerably short time.
A simple modelling approach of the high pour point crude oil transportationhas been obtained using Multi Phase Flow Dynamic Model OLGA to studycharacteristic of the flow in pipeline through a hill, and predict criticaloperation conditions to avoid unexpected transportation failure in thefuture.
Oil Production from Basement Reservoirs OIL PRODUCTION FROM BASEMENT RESERVOIRS - EXAMPLES FROM INDONESIA, USA AND VENEZUELA Tako Koning, Texaco Angola Inc., Luanda, Angola Abstract. Oil is produced from basement rocks in a number of countries including China, Vietnam, former USSR (West Siberia), Ukraine, Indonesia, Libya, Algeria, Morocco, Egypt, USA, Brazil and Venezuela. Oil fields producing from basement in Indonesia, United States, and Venezuela are described herein and serve as models for basement oil fields exploration and production. contacts, and a possible unrecognized water-
bearing fracture system. The Tanjung field in the Barito Basin, Although oil production from basement South Kalimantan, was discovered in 1938 and rocks is not a common occurrence worldwide, has produced over 21 million barrels of oil there is significant oil production from such from pre-Tertiary basement rocks. Oil occurs reservoirs in a number of countries. Two in volcanics, pyroclastics, and metamorphosed fields in Indonesia, Beruk Northeast and sandstones and claystones, which are locally Tanjung, serve as examples that commercial deeply weathered and fractured. The Beruk volumes of oil can be produced from basement Northeast and Tanjung fields share many in Indonesia. Indeed, recent successful similarities. For example, both fields occur exploration for gas in South Sumatra has within faulted anticlines. The overlying reinforced the concept that basement is a valid thickness of Tertiary sediments in both fields exploration target in Western Indonesia and is less than 2000 meters. The likely oil source that whenever possible, wells drilled through rocks for these fields are the adjacent and the Tertiary objectives should be deepened into deeper Tertiary shales. The Beruk Northeast basement to evaluate possible oil or gas and Tanjung fields indicate that pre-Tertiary accumulations. In Kansas, oil is produced basement is a valid oil exploration objective in from fractured quartzites whereas in the Tertiary basins in Western Indonesia and California, oil is produced from fractured that, whenever feasible, exploration wells in schists. In Venezuela, prolific oil wells these basins should be drilled into basement. produce from fractured granite in the La Paz Indeed, exploration targeted for basement and Mara oil fields. hydrocarbons has met with recent success in South Sumatra, where operator Gulf Indonesia INDONESIA has reported the significant Suban gas discovery. Three wells drilled in 1999 in the Oil production from pre-Tertiary basement Suban field have defined a gas pool located rocks is rare within the Tertiary back arc within fractured pre-Tertiary granites. Gas (foreland) basins of Western Indonesia. The flow rates of 26 MMCFGPD were obtained Beruk Northeast field is the only field in the from the Durian Mabok-2 well. Test data prolific Central Sumatra Basin that produces combined with seismic mapping indicates a from basement (Koning & Darm