Arisandy, Mellinda (PETRONAS Carigali Indonesia Operations) | Mazied, Miftah (PETRONAS Carigali Indonesia Operations) | Putra, Bayu P (PETRONAS Carigali Indonesia Operations) | Yogapurana, Erik (PETRONAS Carigali Indonesia Operations) | B Mohd Idris, Jamin Jamil (PETRONAS Carigali Indonesia Operations) | Darmawan, Hendra I. (PETRONAS Carigali Kuala Lumpur)
This paper describes geochemistry analysis, hydrocarbon charge and entrapment model for prolific "MA" Block in the West Natuna Basin. Even though the area is currently at a mature exploration stage, the behaviour of hydrocarbon distribution in the area is still poorly understood and the link between discovered hydrocarbon and possible kitchens is still unknown. This study is an attempt to understand hydrocarbon expulsion, charging and entrapment in "MA" Block to de-risk further exploration efforts.
Several localized inverted half-grabens were identified through seismic interpretation. Nearby wells were then selected in evaluating source rock quality and maturity. In order to determine hydrocarbon expulsion model, 1D-3D burial history and thermal maturity models were constructed using integration of source rock and fluids geochemistry, temperature, seismic, and well data. Hydrocarbon charge and entrapment models were then simulated using 3D basin modeling software and calibrated with existing proven accumulation to produce a risked understanding of hydrocarbon distribution in the study area.
This study suggests that the most possible source rocks are the Late Eocene and Oligocene shales of Lama Formation and Lower Gabus Formations. Both source rocks are indicated by type I & type III kerogen. Lama source rock was confined in the initial grabens and post mature in deep paleo-grabens. This study confirmed that charging is derived from four (4) kitchen areas: Anoa, Gajah, Kakap, and Kambing grabens. The oil samples from "MA" Block indicated lacustrine facies. Rock geochemistry analysis portrayed oil-prone and gas-prone source rock.
In general, hydrocarbon was migrated from the southeastern area (Kambing graben) and southwestern area (Gajah graben). Hydrocarbon was later on accumulated in the nearest structural entrapments (anticlines). In the deep grabens (Kakap and Kambing), the hydrocarbon expulsion was starting as early as 37 Ma and 31 Ma, respectively, while in shallow graben (Anoa) the expulsion was starting at 29 Ma. The earliest structural trap commenced at 21 Ma, aligned with the initial compressional regime that was affecting the West Natuna Basin. Notable accumulative erosion in Miocene was nearly 1000 m at inverted structures, by which partly removed regional seal and reduced reservoir effectiveness. Significant yet-to-find hydrocarbon is predicted to be concentrated in the Anoa, Kakap, and Northeast Kambing area.
Is Surfactant Environmentally Safe for Offshore Use and Discharge? The current presentation date and time shown is a TENTATIVE schedule. The final/confirm presentation schedule will be notified/available in February 2019. Designing Cement Jobs for Success - Get It Right the First Time! Connected Reservoir Regions Map Created From Time-Lapse Pressure Data Shows Similarity to Other Reservoir Quality Maps in a Heterogeneous Carbonate Reservoir. X. Du, Y. Jin, X. Wu, U. of Houston; Y. Liu, X. Wu, O. Awan, J. Roth, K.C. See, N. Tognini, Shell Intl.
By International Petroleum Technology Conference (IPTC) Monday, 25 March 0900-1600 hours Instructors: Olivier Dubrule and Lukas Mosser, Imperial College London Deep Learning (DL) is already bringing game-changing applications to the petroleum industry, and this is certainly the beginning of an enduring trend. Many petroleum engineers and geoscientists are interested to know more about DL but are not sure where to start. This one-day course aims to provide this introduction. The first half of the course presents the formalism of Logistic Regression, Neural Networks and Convolutional Neural Networks and some of their applications. Much of the standard terminology used in DL applications is also presented. In the afternoon, the online environment associated with DL is discussed, from Python libraries to software repositories, including useful websites and big datasets. The last part of the course is spent discussing the most promising subsurface applications of DL.
Iftikhar Ahmed Satti, Deva Ghosh, and Wan Ismail Wan Yusoff, Universiti Teknologi PETRONAS; and M. Jamaal Hoesni, Petronas Carigali Summary This study demonstrates the use of wireline logs for the overpressure-mechanisms analysis in a field in the southwestern Malay basin. The development of overpressure means that the fluid movement in the pores is retarded, both vertically and laterally. In many Tertiary basins, overpressure is mainly generated by compaction disequilibrium caused by a high deposition rate and low permeability in shales. Pore-pressure profiles and crossplots of sonic velocity/vertical effective stress and of velocity/density are used to derive the overpressure-generating mechanisms. The results obtained from the crossplots of 10 wells reveal that in the study area, overpressure is generated by both primary (compactiondisequilibrium) and secondary (fluid-expansion) mechanisms. The overpressure-magnitude analysis suggests that the overpressure generated by the secondary mechanism is very high compared with the primary mechanism. In all the wells, the Eaton (1972) method with an exponent of 3 gives good prediction when overpressure is the result of the compaction-disequilibrium mechanism, but it underpredicted the high pore pressure where the fluidexpansion mechanism is also present. However, by use of a higher Eaton exponent of 5 for the fluid-expansion mechanism, the overpressures are predicted quite well. The Bowers (1995) method, by use of the unloading parameter (U) of 6, is also used for pressure prediction and it gives a reasonably good prediction in the highoverpressure zone of all the wells. Introduction Abnormal pressure, the pressure higher or lower than the normal/ hydrostatic pressure, is often referred to as overpressure or underpressure and has significant importance in geohazard analysis and prediction (Bowers 2002). Accurate pore-pressure prediction is very important for safe drilling, casing-point selection, and well planning in highly overpressured regions. It also has implications in migration modeling for prospect evaluation and seal prediction.
Jong, John (JX Nippon Oil & Gas Exploration Corp.) | Barker, Steven (JX Nippon Oil & Gas Exploration Corp.) | Kessler, Franz L. (Petrotechnical Inspection (M) Sdn. Bhd. currently Lundin Malaysia BV.) | Tran, Quoc Tan (JX Nippon Oil & Gas Exploration Corp.)
The Bunguran Trough, where the BFB (Figure 1) is formed and covers JX Nippon operated Deepwater Block 2F is located roughly in the centre of the SCS, where the national offshore areas of Indonesia, Malaysia and Vietnam converge (Figure 2). It is located between two key lineaments along which tectonic play segment boundaries in the SCS can be defined: 1. The hinge line of the Malay Basin against the Tenggol Arch and Natuna Arch, called the Lupar Line in offshore Sarawak (Figure 3a); it marks the onset of Palaeogene to Middle Miocene subsidence in the eastern half of the SCS, and 2. The Baram Line, a probable extension and/or continuation of the Red River Fault System which defines the post Middle Miocene Sundaland clastic depocentres in coastal Vietnam; curving southeastwards, then eastwards toward Sarawak where it forms the boundary between the Central Luconia carbonate platform and the Baram Delta (Figures 3a and 3b). The Cenozoic evolution of South-East Asia records a diverse array of tectonic processes with rifting, subduction, terrane collision and large-scale continental strike-slip faulting occurring in spatially and 6 IPTC-18197-MS Figure 5--IHS-derived stratigraphic correlation summary for the Malay-Penyu-Natuna and Nam Con Son Basin.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 24879, "Enhanced Multizone Single-Trip Sand-Control System Successfully Treats Six Zones in Offshore Indonesia Well," by Leon Zhou and Indra Gunawan, ConocoPhillips, and Ricki Jannise, Casey Suire, and Tyson Eiman, Halliburton, prepared for the 2014 Offshore Technology Conference Asia, Kuala Lumpur, 25-28 March. The paper has not been peer reviewed.
Although multiple-zone, downhole sand-control-tool systems have been in use since the early 1990s, these systems have been designed for jobs that require only low pump rates with low pressure differentials. Multiple-zone systems capable of high fracturing pump rates and the associated differentials only recently have been introduced to the oil field, but most of these completions have been limited to four or five treated zones. This paper presents a case history from Indonesia in which six discrete zones in an offshore deployment were treated successfully in a single trip.
The Bawal field is located in Block B, 1000 km north of Jakarta, in the South China Sea. The average water depth across the field is 280 ft. The Bawal field was discovered in 1979; the field is approximately 5 km long and 2 km wide. The Bawal reservoirs consist of subangular-to- rounded, well-sorted silt to extremely fine quartz sand. The initial development concept was to drill and complete two to three subsea wells and tie them back to a nearby production facility, Hangtuah, 43 km away. The first-gas-production target was 2012. The reservoirs all require sand control, varying degrees of stimulation, high-rate water packing at rates of 8 to 20 bbl/min, and fracture treatments at rates of 22 to 35 bbl/min.
The operator has completed multiple fields with two dominant completion methods: openhole standalone screen (OHSAS) and cased-hole frac pack (CHFP). The OHSAS completions typically are installed in horizontal wells or very-high-angle wells. The OHSAS requires special reservoir-drill-in fluid with calcium carbonate to drill the reservoir section, run the premium screen, wash the pipe, and conduct mudcake cleanout. Typically, a CHFP is conducted with tubing- conveyed perforation and alternative- flow-path sand screen being run in one trip; then, a frac pack is pumped with viscoelastic fracturing fluid.
Historically, the operator has completed subsea wells with downhole sand control using the OHSAS method for single- zone completions and singletrip frac-pack/high-rate water packs for multizone commingled production. For frac-pack completions, the completion system used previously was capable of treating only up to three zones; therefore, the treatment rate per zone became lower, and there was always an issue with slurry distribution. If more than two to three zones were required per well, a stacked frac-pack completion was implemented.
Completing these wells with conventional stacked sand-control methods meant spending many rig days tripping pipe in and out of each well. The single-trip multizone methods previously used in the area typically would provide only a limited pump rate of up to 10 bbl/min per zone and pressure ratings of 6,000 psi. For the new wells, the fracture treatments would require a more-robust system that would include a pressure rating of 10,000 psi because of sandout conditions.
Another challenge was that commingling these zones into one well has historically resulted in 50% less recovery compared with single-zone completions. Early water breakthrough coming in from one of the zones would cause the well to load up and die. Therefore, the operator also wanted to include installation of an intelligent-completion system that would allow zonal isolation without intervention, to optimize reserves recovery. The multizone frac-pack completion not only would have to be capable of completing up to six zones in one run but also would have to be compatible with the planned intelligent-system equipment.
Although multiple-zone, downhole sand-control tool systems have been in use since the early 1990s, these systems had been designed for jobs requiring low-pump-rates with low-pressure differentials. Multiple-zone systems capable of high fracturing pump rates and the associated differentials only recently have been introduced to the oilfield. Although these jobs are becoming more common, most of the completions have been limited to four or five discretely treated zones.
This paper presents a case history from Indonesia in which a high pump rate, high differential pressure-rated single-trip multiple zone-sand control tool system was capable of treating six discrete zones in an offshore deployment. The challenges for this completion were numerous. Manufacturing lead time was very short, and the system would have to be adapted to the unique requirements of the completion design and the use of new components. Since the proppant and pump rating limit testing for these systems had been based on five zones, complicated calculations and extrapolations had to be used to ensure that the crossover tool would survive the erosive effects of treating six zones.
To provide assurance of the service tool’s elastomeric seal integrity, a testing program was executed between treatments to provide tracking and verification of conditions. Procedures and equipment would be in place to replace the service tools, if any leaks were evident. Since system installation experience was limited in this area, gathering sufficient knowledge and experience for system deployment had to be addressed quickly. This would require sharing of lessons learned, use of experienced personnel from previous installations, and conducting of detailed training discussions between subject matter experts and service personnel. Deployment challenges and solutions, successes experienced at the well site, and the actual performance of the operations will be detailed in the paper.
This paper applies a single well numerical model using a reservoir simulator and accommodating geological data such as depth structure, gross and net thickness, and distribution of petrophysical properties to interpret a DST data. History matching pressures and rates of the DST data is conducted after incorporating the geological, reservoir engineering, and production data.
In this single well simulation study, three DST data from well North Belut 3 are as the matching target used in the history matching using commercial numerical simulator with black oil formulation and three dimensional models. The PVT data is generated from an EOS model in which pseudoization is applied to reduce the components into 9. A one and a half foot model, or total of 1309 Z-grid dimension, is used to accommodate facies inconsistency and fluid gradient changes. Capillary pressures are obtained from mercury injection laboratory experiment of samples from four wells and are distributed according to permeability range values.On the other hand, the permeability curves are generated using the Corey function.
The interpretation through the history matching process is described in steps to show advantages of using this method. Correct PVT fluid type, absolute permeability, and skin factor are the most affected on the pressure and rate matching process. The steps could explain and improve the understanding of reservoir characterization. The results are also compared with the analytical interpretations, which study is already done before by other person, to see the reliability. A good agreement on the permeability value is gained, with a possiblility of different net to gross ration interpretation. The skin factors of the numerical method are reasonably positive values, and tend to much less than the analytical results. This suggests that the near well bore damage may not as bad as the analytical interpretation implied.
Among one of methods to understand the characteristic of reservoir is through welltest interpretation. Of which welltest type to be used, depends on the development stage of a reservoir.Drill Stem test is a welltest that usually runs on new wells. Interpretation of the Drill Stem Test (DST) results in permeability, near-wellbore formation condition or skin factor, fluids characteristic, and reservoir boundary. The interpretation of DST curve can be done using the available analytical solutions, or numerical solutions as what we do here in this paper.
For a complex problem such as multiphase flow of a condensate system, a numerical simulation is a great advantage as analytical solution doest take into account of the mass mass transfer between oil and gas phases during transient flow, but, it rather simplifies these chemical activities into a steady state process.To accommodate such a fluid system and its geological system, a black oil reservoir simulator is generated together with input of PVT laboratory and geology data.A history matching process was conducted after a complete modelling of reservoir in the simulator.The history matching will need a parameter adjustment such as permeability and skin factor value. The agreements of curve profiles between welltest result and simulation result, will do the validity of the model characterization. The quantitative parameter results such as skin, effective permeability, are then compared with the available analytical interpretation results. A reliable explanation of the differences between analytical solution and numerical sulitions is gained.
Adhia, Gautam (ChevronTexaco Corporation) | Pellegrino, Sean (ChevronTexaco Corporation) | Ximenes, Maria- Celia (ChevronTexaco Corporation) | Awashima, Yuji (IHI Marine United Inc) | Kakimoto, Masataka (IHI Marine United Inc) | Ando, Toshihiko (IHI Marine United Inc)